PATTERSON UTI ENERGY INC - Quarter Report: 2017 June (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended June 30, 2017

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

For the transition period from to

Commission file number 0-22664

Patterson-UTI Energy, Inc.

(Exact name of registrant as specified in its charter)

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

10713 W. SAM HOUSTON PKWY N, SUITE 800 HOUSTON, TEXAS		77064
(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 ☑ 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 ☑ 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,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act:

Large accelerated filer	☑	Accelerated filer	☐	Smaller reporting company	☐

Non-accelerated filer	☐			Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) 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 ☑

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

213,350,278 shares of common stock, $0.01 par value, as of August 1, 2017

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

	PART I — FINANCIAL INFORMATION
		Page
ITEM 1.	Financial Statements
	Unaudited condensed consolidated balance sheets	3
	Unaudited condensed consolidated statements of operations	4
	Unaudited condensed consolidated statements of comprehensive loss	5
	Unaudited condensed consolidated statement of changes in stockholders’ equity	6
	Unaudited condensed consolidated statements of cash flows	7
	Notes to unaudited condensed consolidated financial statements	8
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	39
ITEM 4.	Controls and Procedures	40

	PART II — OTHER INFORMATION

ITEM 1.	Legal Proceedings	41
ITEM 1A.	Risk Factors	41
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	41
ITEM 6.	Exhibits	42
Signature		43

PART I — FINANCIAL INFORMATION

ITEM 1. Financial Statements

The following unaudited condensed consolidated financial statements include all adjustments which are, in the opinion of management, necessary for a fair statement of the results for the interim periods presented.

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited, in thousands, except share data)

	June 30,			December 31,
	2017			2016
ASSETS
Current assets:
Cash and cash equivalents	$	40,132		$	35,152
Accounts receivable, net of allowance for doubtful accounts of $3,116 and $3,191 at June 30, 2017 and December 31, 2016, respectively		433,366			148,091
Federal and state income taxes receivable		3,666			2,126
Inventory		36,132			20,191
Other		58,453			41,322
Total current assets		571,749			246,882
Property and equipment, net		4,232,194			3,408,963
Goodwill and intangible assets		540,273			88,966
Deposits on equipment purchases		12,917			16,050
Deferred tax assets, net		1,339			4,124
Other		45,584			7,306
Total assets	$	5,404,056		$	3,772,291
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	255,327		$	125,667
Accrued expenses		217,521			139,148
Total current liabilities		472,848			264,815
Borrowings under revolving credit facility		115,000			—
Long-term debt, net of debt issuance cost of $1,390 and $1,563 at June 30, 2017 and December 31, 2016, respectively		598,610			598,437
Deferred tax liabilities, net		588,594			650,661
Other		11,201			9,654
Total liabilities		1,786,253			1,523,567
Commitments and contingencies (see Note 11)
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 256,914,385 and 191,525,872 issued and 213,328,565 and 148,133,255 outstanding at June 30, 2017 and December 31, 2016, respectively		2,569			1,915
Additional paid-in capital		2,575,401			1,042,696
Retained earnings		1,953,023			2,116,341
Accumulated other comprehensive income (loss)		1,854			(1,134	)
Treasury stock, at cost, 43,585,820 and 43,392,617 shares at June 30, 2017 and December 31, 2016, respectively		(915,044	)		(911,094	)
Total stockholders' equity		3,617,803			2,248,724
Total liabilities and stockholders' equity	$	5,404,056		$	3,772,291

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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited, in thousands, except per share data)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
Operating revenues:
Contract drilling	$	270,111		$	115,235		$	428,839		$	283,894
Pressure pumping		290,044			73,950			431,218			170,263
Other		19,031			4,722			24,304			8,689
Total operating revenues		579,186			193,907			884,361			462,846
Operating costs and expenses:
Contract drilling		180,658			63,803			288,879			144,701
Pressure pumping		233,900			69,546			352,913			157,359
Other		12,671			1,650			15,930			3,740
Depreciation, depletion, amortization and impairment		219,328			170,975			375,545			347,745
Selling, general and administrative		23,478			17,087			42,330			35,059
Merger and integration expenses		51,193			—			56,349			—
Other operating income, net		(1,806	)		(4,822	)		(14,710	)		(6,167	)
Total operating costs and expenses		719,422			318,239			1,117,236			682,437
Operating loss		(140,236	)		(124,332	)		(232,875	)		(219,591	)
Other income (expense):
Interest income		642			100			1,048			210
Interest expense, net of amount capitalized		(9,075	)		(10,678	)		(17,345	)		(21,478	)
Other		131			17			148			33
Total other expense		(8,302	)		(10,561	)		(16,149	)		(21,235	)
Loss before income taxes		(148,538	)		(134,893	)		(249,024	)		(240,826	)
Income tax benefit		(56,354	)		(49,027	)		(93,301	)		(84,457	)
Net loss	$	(92,184	)	$	(85,866	)	$	(155,723	)	$	(156,369	)
Net loss per common share:
Basic	$	(0.46	)	$	(0.58	)	$	(0.86	)	$	(1.06	)
Diluted	$	(0.46	)	$	(0.58	)	$	(0.86	)	$	(1.06	)
Weighted average number of common shares outstanding:
Basic		201,204			145,944			180,747			145,857
Diluted		201,204			145,944			180,747			145,857
Cash dividends per common share	$	0.02		$	0.02		$	0.04		$	0.12

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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(unaudited, in thousands)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
Net loss	$	(92,184	)	$	(85,866	)	$	(155,723	)	$	(156,369	)
Other comprehensive income, net of taxes of $0 for all periods:
Foreign currency translation adjustment		1,939			469			2,988			7,147
Total comprehensive loss	$	(90,245	)	$	(85,397	)	$	(152,735	)	$	(149,222	)

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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(unaudited, in thousands)

												Accumulated
	Common Stock					Additional						Other
	Number of					Paid-in			Retained			Comprehensive			Treasury
	Shares			Amount		Capital			Earnings			Income (Loss)			Stock			Total
Balance, December 31, 2016		191,526		$	1,915	$	1,042,696		$	2,116,341		$	(1,134	)	$	(911,094	)		2,248,724
Net loss		—			—		—			(155,723	)		—			—			(155,723	)
Foreign currency translation adjustment		—			—		—			—			2,988			—			2,988
Equity offering		18,170			182		471,388			—			—			—			471,570
Shares issued for acquisition		46,298			463		1,038,933			—			—			—			1,039,396
Exercise of stock options		10			—		223			—			—			—			223
Issuance of restricted stock		891			9		(9	)		—			—			—			—
Vesting of restricted stock units		34			—		—			—			—			—			—
Forfeitures of restricted stock		(15	)		—		—			—			—			—			—
Stock-based compensation		—			—		22,170			—			—			—			22,170
Payment of cash dividends		—			—		—			(7,595	)		—			—			(7,595	)
Purchase of treasury stock		—			—		—			—			—			(3,950	)		(3,950	)
Balance, June 30, 2017		256,914		$	2,569	$	2,575,401		$	1,953,023		$	1,854		$	(915,044	)	$	3,617,803

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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited, in thousands)

	Six Months Ended
	June 30,
	2017			2016
Cash flows from operating activities:
Net loss	$	(155,723	)	$	(156,369	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, amortization and impairment		375,545			347,745
Dry holes and abandonments		28			—
Deferred income tax benefit		(90,684	)		(58,643	)
Stock-based compensation expense		22,170			14,192
Net gain on asset disposals		(15,367	)		(7,267	)
Tax expense on stock-based compensation		—			(2,995	)
Amortization of debt issuance costs		173			723
Changes in operating assets and liabilities:
Accounts receivable		(135,542	)		91,559
Income taxes receivable		(1,141	)		(2,329	)
Inventory and other assets		(29,186	)		3,795
Accounts payable		58,372			(25,738	)
Accrued expenses		(13,002	)		(21,658	)
Other liabilities		(258	)		(1,088	)
Net cash provided by operating activities		15,385			181,927
Cash flows from investing activities:
Acquisition, net of cash acquired		(434,194	)		—
Purchases of property and equipment		(186,790	)		(51,834	)
Proceeds from disposal of assets		34,997			12,350
Net cash used in investing activities		(585,987	)		(39,484	)
Cash flows from financing activities:
Proceeds from equity offering		471,570			—
Purchases of treasury stock		(3,727	)		(3,611	)
Dividends paid		(7,595	)		(17,665	)
Repayment of long-term debt					(25,000	)
Proceeds from borrowings under revolving credit facility		161,000			—
Repayment of borrowings under revolving credit facility		(46,000	)		—
Net cash provided by (used in) financing activities		575,248			(46,276	)
Effect of foreign exchange rate changes on cash		334			114
Net increase in cash and cash equivalents		4,980			96,281
Cash and cash equivalents at beginning of period		35,152			113,346
Cash and cash equivalents at end of period	$	40,132		$	209,627
Supplemental disclosure of cash flow information:
Net cash (paid) received during the period for:
Interest, net of capitalized interest of $409 in 2017 and $286 in 2016	$	(16,640	)	$	(20,252	)
Income taxes	$	967		$	19,603
Non-cash investing and financing activities:
Net increase in payables for purchases of property and equipment	$	33,938		$	9,283
Issuance of common stock for business acquisition	$	1,039,396		$	—
Net decrease in deposits on equipment purchases	$	3,133		$	4,397

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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Basis of Consolidation and Presentation

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

The unaudited interim condensed consolidated financial statements have been prepared by management of the Company pursuant to the rules and regulations of the United States 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 (“U.S. GAAP”) 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 recurring adjustments considered necessary for a fair statement of the information in conformity with U.S. GAAP have been included. The unaudited condensed consolidated balance sheet as of December 31, 2016, as presented herein, was derived from the audited consolidated balance sheet of the Company, but does not include all disclosures required by U.S. GAAP. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and related notes included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016. The results of operations for the three and six months ended June 30, 2017 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 loss, which is a separate component of stockholders’ equity.

In 2017, the Company adopted new guidance for the presentation of deferred tax liabilities and assets and such guidance was applied retrospectively, resulting in the retroactive adjustment of current deferred tax assets, net and deferred tax liabilities, net as of December 31, 2016. During the fourth quarter of 2016, the Company changed its reporting segment presentation, as the Company no longer considers its oil and natural gas exploration and production activities to be significant to an understanding of the Company’s results. The Company now presents the oil and natural gas exploration and production activities, oilfield rental tool business, pipe handling components and related technology business and Middle East/North Africa business as “Other,” and “Corporate” reflects only corporate activities. This change in segment presentation was applied retrospectively to all periods presented herein (See Note 6).

On December 12, 2016, the Company entered into an Agreement and Plan of Merger (the “merger agreement”) with Seventy Seven Energy Inc. (“SSE”), and the merger closed on April 20, 2017 (the “merger date”). The Company’s results include the results of operations of SSE since the merger date (See Note 2).

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

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

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

The following table presents information necessary to calculate net loss per share for the three and six months ended June 30, 2017 and 2016 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						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
BASIC EPS:
Net loss	$	(92,184	)	$	(85,866	)	$	(155,723	)	$	(156,369	)
Adjust for loss attributed to holders of non-vested restricted stock		—			846			—			1,526
Loss attributed to other common stockholders	$	(92,184	)	$	(85,020	)	$	(155,723	)	$	(154,843	)
Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock		201,204			145,944			180,747			145,857
Basic net loss per common share	$	(0.46	)	$	(0.58	)	$	(0.86	)	$	(1.06	)
DILUTED EPS:
Loss attributed to other common stockholders	$	(92,184	)	$	(85,020	)	$	(155,723	)	$	(154,843	)
Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock		201,204			145,944			180,747			145,857
Add dilutive effect of potential common shares		—			—			—			—
Weighted average number of diluted common shares outstanding		201,204			145,944			180,747			145,857
Diluted net loss per common share	$	(0.46	)	$	(0.58	)	$	(0.86	)	$	(1.06	)
Potentially dilutive securities excluded as anti-dilutive		9,475			9,370			9,475			9,370

2. Acquisitions

On April 20, 2017, pursuant to the merger agreement, a subsidiary of the Company was merged with and into SSE, with SSE continuing as the surviving entity and one of the Company’s wholly owned subsidiaries (the “SSE merger”). Pursuant to the terms of the merger agreement, the Company acquired all of the issued and outstanding shares of common stock of SSE, in exchange for approximately 46.3 million shares of common stock of the Company. Concurrent with the closing of the merger, the Company repaid all of the outstanding debt of SSE totaling $472 million. Based on the closing price of the Company’s common stock on April 20, 2017, the total fair value of the consideration transferred to effect the acquisition of SSE was approximately $1.5 billion. On April 20, 2017, following the SSE merger, SSE was merged with and into a newly-formed subsidiary of the Company named Seventy Seven Energy LLC (“SSE LLC”), with SSE LLC continuing as the surviving entity and one of the Company’s wholly owned subsidiaries.

Through the SSE merger, the Company acquired a fleet of 91 drilling rigs, 36 of which the Company considers to be APEX® class rigs. Additionally, through the SSE merger, the Company acquired approximately 500,000 horsepower of modern, efficient fracturing equipment located in Oklahoma and Texas. The oilfield rentals business acquired through the SSE merger has a modern, well-maintained fleet of premium rental tools, and it provides specialized services for land-based oil and natural gas drilling, completion and workover activities.

The merger has been accounted for as a business combination using the acquisition method. Under the acquisition method of accounting, the fair value of the consideration transferred is allocated to the tangible and intangible assets acquired and the liabilities assumed based on their estimated fair values as of the acquisition date, with the remaining unallocated amount recorded as goodwill.

The total fair value of the consideration transferred was determined as follows (in thousands, except stock price):

Shares of Company common stock issued to SSE shareholders		46,298
Company common stock price on April 20, 2017	$	22.45
Fair value of common stock issued	$	1,039,396
Plus SSE long-term debt repaid by Company	$	472,000
Total fair value of consideration transferred	$	1,511,396

The final determination of the fair value of assets acquired and liabilities assumed at the merger date will be completed as soon as possible, but no later than one year from the merger date (the “measurement period”). The Company’s preliminary purchase price allocation is subject to revision as additional information about the fair value of assets and liabilities becomes available. Additional information that existed as of the merger date, but at the time was unknown to the Company, may become known to the Company during the remainder of the measurement period. The final determination of fair value may differ materially from these preliminary estimates. The following table represents the preliminary allocation of the total purchase price of SSE to the assets acquired and the liabilities assumed based on the fair value at the merger date, with the excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill (in thousands):

Identifiable assets acquired
Cash and cash equivalents	$	37,806
Accounts receivable		149,598
Inventory		8,036
Other current assets		19,250
Property and equipment		984,430
Other long-term assets		14,546
Intangible assets		22,500
Total identifiable assets acquired		1,236,166
Liabilities assumed
Accounts payable and accrued liabilities		130,100
Deferred income taxes		31,402
Other long-term liabilities		1,734
Total liabilities assumed		163,236
Net identifiable assets acquired		1,072,930
Goodwill		438,466
Total net assets acquired	$	1,511,396

The acquired goodwill is not deductible for tax purposes. Among the factors that contributed to a purchase price resulting in the recognition of goodwill was SSE’s reputation as an experienced provider of high-quality contract drilling and pressure pumping services in a safe and efficient manner. See Note 7 for a breakdown of goodwill acquired by operating segment.

A portion of the fair value consideration transferred has been provisionally assigned to identifiable intangible assets as follows:

	Fair Value		Weighted Average Useful Life
	(in thousands)		(in years)
Assets
Favorable drilling contracts	$	22,500	1
Liabilities
Unfavorable drilling contracts	$	2,532	1

The results of SSE’s operations since the merger date are included in our consolidated statement of operations. Operations acquired in the SSE merger contributed revenues of $190 million and a pretax loss of $16.9 million for the period from the merger date until June 30, 2017. The following pro forma condensed combined financial information was derived from the historical financial statements of the Company and SSE and gives effect to the merger as if it had occurred on January 1, 2016. The below information reflects pro forma adjustments based on available information and certain assumptions the Company believes are reasonable, including (i) adjustments related to the depreciation and amortization of the fair value of acquired intangibles and fixed assets, (ii) removal of the historical interest expense of SSE, (iii) tax benefit of the aforementioned pro forma adjustments, and (iv) adjustments related to the common shares outstanding to reflect the impact of the consideration exchanged in the merger. Additionally, pro forma loss for the three months ended June 30, 2017 was adjusted to exclude the Company’s merger related costs of $51.2 million and SSE’s merger related costs of $28.9 million. The pro forma loss for the six months ended June 30, 2017 was adjusted to exclude the Company’s merger related costs of $56.3 million and SSE’s merger related costs of $36.7 million. The pro forma results of operations do not include any cost savings or other synergies that may result from the SSE merger or any estimated costs that have been or will be incurred by the Company to integrate the SSE operations. The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the SSE merger taken place on January 1, 2016; furthermore, the financial information is not intended to be a projection of future results. The following table summarizes selected financial information of the Company on a pro forma basis (in thousands, except per share data):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016

Revenues	$	631,770		$	332,027		$	1,126,914		$	756,327
Net loss		(85,184	)		(133,530	)		(117,317	)		(229,295	)
Loss per share		(0.40	)		(0.63	)		(0.56	)		(1.09	)

3. Stock-based Compensation

The Company uses share-based payments to compensate employees and non-employee directors. The Company recognizes the cost of share-based payments under the fair-value-based method. Share-based awards consist of equity instruments in the form of stock options, restricted stock or restricted stock units that have included service conditions and, in certain cases, performance conditions. The Company’s share-based awards also include share-settled performance unit 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.

The Patterson-UTI Energy, Inc. 2014 Long-Term Incentive Plan (the “2014 Plan”) was originally approved by the Company’s stockholders effective as of April 17, 2014. On June 29, 2017, the Company’s stockholders approved the amendment and restatement of the 2014 Plan (the “Amended and Restated Plan”) to increase the number of shares available for future issuance under the plan to 10,049,156 shares. The aggregate number of shares of Common Stock authorized for grant under the Amended and Restated Plan is 18.9 million, which includes the 9.1 million shares previously authorized under the 2014 Plan.

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 such 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. No options were granted in the three or six months ended June 30, 2017. 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, 2016 follow:

	Three Months Ended			Six Months Ended
	June 30,			June 30,
	2016			2016
Volatility		34.87	%		35.13	%
Expected term (in years)		5.00			5.00
Dividend yield		2.16	%		2.19	%
Risk-free interest rate		1.40	%		1.42	%

Stock option activity from January 1, 2017 to June 30, 2017 follows:

				Weighted
				Average
	Underlying			Exercise Price
	Shares			Per Share
Outstanding at January 1, 2017		6,687,150		$	20.68
Exercised		(10,000	)	$	22.29
Expired		(600,000	)	$	24.17
Outstanding at June 30, 2017		6,077,150		$	20.34
Exercisable at June 30, 2017		5,271,650		$	20.53

Restricted Stock — For all restricted stock awards made 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, 2017 to June 30, 2017 follows:

				Weighted
				Average Grant
				Date Fair Value
	Shares			Per Share
Non-vested restricted stock outstanding at January 1, 2017		1,427,455		$	22.26
Granted		890,904		$	21.78
Vested		(674,852	)	$	23.94
Forfeited		(14,853	)	$	22.92
Non-vested restricted stock outstanding at June 30, 2017		1,628,654		$	21.30

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 certain 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, 2017 to June 30, 2017 follows:

				Weighted
				Average Grant
				Date Fair Value
	Shares			Per Share
Non-vested restricted stock units outstanding at January 1, 2017		191,655		$	19.85
Assumed (1)		505,551		$	22.45
Vested		(34,189	)	$	24.35
Forfeited		(17,781	)	$	22.27
Non-vested restricted stock units outstanding at June 30, 2017		645,236		$	21.58

(1)

Restricted stock unit awards under the Seventy Seven Energy Inc. 2016 Omnibus Incentive Plan, which was adopted, assumed, amended and renamed by the Company in connection with the SSE merger. No additional awards will be made under this plan.

Performance Unit Awards. The Company has granted stock-settled performance unit awards to certain executive officers (the “Performance Units”) on an annual basis since 2010. The Performance Units provide for the recipients to receive a grant of shares of common stock upon the achievement of certain performance goals during a specified period established by the Compensation Committee. The performance period for the Performance Units is the three-year period commencing on April 1 of the year of grant, except that for the Performance Units granted in 2013 the performance period was extended pursuant to its terms, as described below, and for the Performance Units granted in 2017 the three-year performance period commenced on May 1.

The performance goals for the 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 respective Performance Units. Generally, the recipients will receive a target number of shares if the Company’s total shareholder return during the performance period, when compared to the peer group, is at the 50^th percentile. If the Company’s total shareholder return during the performance period, when compared to the peer group, is at the 75^th percentile or higher, then the recipients will receive two times the target number of shares. If the Company’s total shareholder return during the performance period, when compared to the peer group, is at the 25^th percentile, then the recipients will only receive one-half of the target number of shares. If the Company’s total shareholder return during the performance period, when compared to the peer group, is between the 25^th and 75^th percentile, then the shares to be received by the recipients will be determined on a pro-rata basis.

For the Performance Units awarded prior to 2016, there is no payout unless the Company’s total shareholder return is positive and, when compared to the peer group, is at or above the 25^thpercentile. In respect of the 2013 Performance Units, for which the performance period ended March 31, 2016, the Company’s total shareholder return for the performance period was negative, the Company’s total shareholder return for the performance period when compared to the peer group was above the 75^th percentile, and there was no payout; provided, however, that pursuant to the terms of those 2013 awards, if, during the two-year period ending March 31, 2018, the Company’s total shareholder return for any 30 consecutive day period equals or exceeds 18 percent on an annualized basis from April 1, 2013 through the last day of such 30 consecutive day period, and the recipient is actively employed by the Company through the last day of the extended performance period, then the Company will issue to the recipient the number of shares equal to the amount the recipient would have been entitled to receive had the Company’s total shareholder return been positive during the initial three-year performance period.

For the Performance Units granted in April 2016, if the Company’s total shareholder return is negative, and, when compared to the peer group is at or above the 25th percentile, then the recipients will receive one-half of the number of shares they would have received had the Company’s total shareholder return been positive. For the Performance Units granted in May 2017, the payout is based on relative performance and does not have an absolute performance requirement.

The total target number of shares with respect to the Performance Units for the awards in 2013-2017 is set forth below:

	2017		2016		2015		2014		2013
	Performance		Performance		Performance		Performance		Performance
	Unit Awards		Unit Awards		Unit Awards		Unit Awards		Unit Awards
Target number of shares		186,198		185,000		190,600		154,000		236,500

Because the 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 Performance Units is set forth below (in thousands):

	2017		2016		2015		2014		2013
	Performance		Performance		Performance		Performance		Performance
	Unit Awards		Unit Awards		Unit Awards		Unit Awards		Unit Awards
Fair value at date of grant	$	5,780	$	3,854	$	4,052	$	5,388	$	5,564

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

	2017		2016		2015		2014		2013
	Performance		Performance		Performance		Performance		Performance
	Unit Awards		Unit Awards		Unit Awards		Unit Awards		Unit Awards
Three months ended June 30, 2017	$	321	$	321	$	338	NA		NA
Three months ended June 30, 2016	NA		$	321	$	338	$	449	NA
Six months ended June 30, 2017	$	321	$	642	$	675	$	449	NA
Six months ended June 30, 2016	NA		$	321	$	675	$	898	$	464

4. Inventory

Inventory consisted of the following at June 30, 2017 and December 31, 2016 (in thousands):

	June 30,		December 31,
	2017		2016
Finished goods	$	1,444	$	—
Work-in-process		1,999		1,803
Raw materials and supplies		32,689		18,388
Inventory	$	36,132	$	20,191

5. Property and Equipment

Property and equipment consisted of the following at June 30, 2017 and December 31, 2016 (in thousands):

	June 30,			December 31,
	2017			2016
Equipment	$	7,832,117		$	6,809,129
Oil and natural gas properties		208,299			201,568
Buildings		155,992			97,029
Land		22,475			22,270
Total property and equipment		8,218,883			7,129,996
Less accumulated depreciation, depletion and impairment		(3,986,689	)		(3,721,033	)
Property and equipment, net	$	4,232,194		$	3,408,963

On a periodic basis, the Company evaluates its fleet of drilling rigs for marketability based on the condition of inactive rigs, expenditures that would be necessary to bring them to working condition and the expected demand for drilling services by rig type (such as drilling conventional, vertical wells versus drilling longer, horizontal wells using higher specification rigs). The components comprising rigs that will no longer be marketed are evaluated, and those components with continuing utility to the Company’s other marketed rigs are transferred to other rigs or to the Company’s yards to be used as spare equipment. The remaining components of these rigs are retired. During the three months ended June 30, 2017, the Company recorded an impairment charge of $29.0 million for the write-down of drilling equipment that will have no continuing utility as a result of the upgrade of certain rigs to super-spec capability.

In addition, the Company evaluates the recoverability of its long-lived assets whenever events or changes in circumstances indicate that their carrying amounts may not be recoverable (a “triggering event”). Based on recent commodity prices, the Company’s results of operations for the three and six month periods ended June 30, 2017 and management’s expectations of operating results in future periods, the Company concluded that no triggering event occurred during the six months ended June 30, 2017 with respect to its contract drilling or pressure pumping segments. Management’s expectations of future operating results were based on the assumption that activity levels in both segments will continue to improve throughout 2017 in response to relatively stable oil prices.

The Company reviews its proved oil and natural gas properties for impairment whenever a triggering event occurs, such as downward revisions in reserve estimates or decreases in expected future oil and natural gas prices. Proved properties are grouped by field, and undiscounted cash flow estimates are prepared based on the Company’s expectation of future pricing over the lives of the respective fields. These cash flow estimates are reviewed by an independent petroleum engineer. If the net book value of a field exceeds its undiscounted cash flow estimate, impairment expense is measured and recognized as the difference between net book value and fair value. The fair value estimates used in measuring impairment are based on internally developed unobservable inputs including reserve volumes and future production, pricing and operating costs (Level 3 inputs in the fair value hierarchy of fair value accounting). The expected future net cash flows are discounted using an annual rate of 10% to determine fair value. The Company reviews unproved oil and natural gas properties quarterly to assess potential impairment. The Company’s impairment assessment is made on a lease-by-lease basis and considers factors such as the Company’s intent to drill, lease terms and abandonment of an area. If an unproved property is determined to be impaired, the related property costs are expensed. Impairment expense related to proved and unproved oil and natural gas properties totaled $1.7 million in the second quarter of 2017 and $2.2 million for the six months ended June 30, 2017 and is included in depreciation, depletion, amortization and impairment in the condensed consolidated statements of operations.

6. Business Segments

The Company’s revenues, loss before income taxes and identifiable assets are primarily attributable to two business segments: (i) contract drilling of oil and natural gas wells and (ii) pressure pumping services. Each of these segments represents a distinct type of business and has a separate management team that reports 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.

The following tables summarize selected financial information relating to the Company’s business segments (in thousands):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
Revenues:
Contract drilling	$	270,487		$	115,235		$	429,542		$	283,992
Pressure pumping		290,044			73,950			431,218			170,263
Other operations (a)		19,642			4,722			25,260			8,689
Elimination of intercompany revenues (b)		(987	)		—			(1,659	)		(98	)
Total revenues	$	579,186		$	193,907		$	884,361		$	462,846

Income (loss) before income taxes:
Contract drilling	$	(73,362	)	$	(70,449	)	$	(135,068	)	$	(105,545	)
Pressure pumping		4,636			(46,025	)		(18,255	)		(89,984	)
Other operations		(4,563	)		740			(6,514	)		(2,491	)
Corporate		(68,753	)		(13,420	)		(87,748	)		(27,738	)
Other operating income, net (c)		1,806			4,822			14,710			6,167
Interest income		642			100			1,048			210
Interest expense		(9,075	)		(10,678	)		(17,345	)		(21,478	)
Other		131			17			148			33
Loss before income taxes	$	(148,538	)	$	(134,893	)	$	(249,024	)	$	(240,826	)

Depreciation, depletion, amortization and impairment
Contract drilling	$	161,414		$	120,402		$	271,973		$	241,501
Pressure pumping		47,805			47,400			90,055			96,970
Other operations		8,120			1,805			10,292			6,537
Corporate		1,989			1,368			3,225			2,737
Total depreciation, depletion, amortization and impairment	$	219,328		$	170,975		$	375,545		$	347,745

Capital expenditures
Contract drilling	$	71,326		$	16,570		$	115,547		$	28,450
Pressure pumping		38,780			11,780			58,193			19,332
Other operations		8,017			1,692			12,369			3,220
Corporate		227			491			681			832
Total capital expenditures	$	118,350		$	30,533		$	186,790		$	51,834

	June 30,		December 31,
	2017		2016
Identifiable assets:
Contract drilling	$	3,943,899	$	3,032,819
Pressure pumping		1,166,406		653,630
Other operations		164,200		48,885
Corporate (d)		129,551		36,957
Total assets	$	5,404,056	$	3,772,291

(a)	Other operations includes the Company’s oilfield rental tools business, pipe handling components and related technology business, the oil and natural gas working interests and the Middle East/North Africa business.

(b)	For 2016, intercompany revenues consists of contract drilling intercompany revenues for services provided to other operations. For 2017, intercompany revenues also includes revenues from other operations for services provided to contract drilling, pressure pumping and within other operations.

(c)

Other operating income includes net gains associated with the disposal of assets related to corporate strategy decisions of the executive management group. Accordingly, the related gains have been excluded from the operating results of specific segments. This caption also includes expenses related to certain legal settlements net of insurance reimbursements.

(d)	Corporate assets primarily include cash on hand and certain property and equipment.

7. Goodwill and Intangible Assets

Goodwill — Goodwill by operating segment as of June 30, 2017 and changes for the six months then ended are as follows (in thousands):

	Contract		Pressure
	Drilling		Pumping		Total
Balance at beginning of period	$	86,234	$	—	$	86,234
Changes to goodwill		300,819		137,647		438,466
Balance at end of period	$	387,053	$	137,647	$	524,700

There were no accumulated impairment losses related to goodwill as of June 30, 2017 or December 31, 2016.

Goodwill is evaluated at least annually as of December 31, or when circumstances require, to determine if the fair value of recorded goodwill has decreased below its carrying value. For impairment testing purposes, goodwill is evaluated at the reporting unit level. The Company’s reporting units for impairment testing are 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, and if this is the case, any necessary goodwill impairment is determined using a quantitative impairment test. From time to time, the Company may perform quantitative testing for goodwill impairment in lieu of performing the qualitative assessment. If the resulting fair value of goodwill is less than the carrying value of goodwill, an impairment loss would be recognized for the amount of the shortfall.

Intangible Assets — The following table presents the gross carrying amount and accumulated amortization of the intangible assets as of June 30, 2017 and December 31, 2016 (in thousands):

	June 30, 2017							December 31, 2016
	Gross					Net		Gross					Net
	Carrying		Accumulated			Carrying		Carrying		Accumulated			Carrying
	Amount		Amortization			Amount		Amount		Amortization			Amount
Customer relationships	$	25,500	$	(24,589	)	$	911	$	25,500	$	(22,768	)	$	2,732
Favorable drilling contracts		22,500		(7,838	)		14,662		—		—			—
	$	48,000	$	(32,427	)	$	15,573	$	25,500	$	(22,768	)	$	2,732

Amortization expense on intangible assets of approximately $8.7 million and $911,000 was recorded in the three months ended June 30, 2017 and 2016, respectively, and amortization expense on intangible assets of approximately $9.7 million and $1.8 million was recorded in the six months ended June 30, 2017 and 2016, respectively.

8. Accrued Expenses

Accrued expenses consisted of the following at June 30, 2017 and December 31, 2016 (in thousands):

	June 30,		December 31,
	2017		2016
Salaries, wages, payroll taxes and benefits	$	34,699	$	21,138
Workers' compensation liability		81,653		67,775
Property, sales, use and other taxes		29,123		6,766
Insurance, other than workers' compensation		9,248		9,566
Accrued interest payable		9,408		6,740
Accrued merger and integration		25,206		-
Other		28,184		27,163
Total	$	217,521	$	139,148

9. Unfavorable Drilling Contracts

As discussed in Note 2, the Company recorded a liability for unfavorable drilling contracts in connection with the SSE merger. This liability is included in the caption “accrued expenses” in the current liabilities section of the condensed consolidated balance sheet. The following table describes the changes to the Company’s unfavorable drilling contracts from the merger date until June 30, 2017 (in thousands):

Liabilities at fair value (See Note 2)	$	2,532
Amortization		(1,586	)
Unfavorable drilling contracts liability at end of period	$	946

10. Long Term Debt

2012 Credit Agreement — On September 27, 2012, the Company entered into a Credit Agreement (the “Base 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 Base Credit Agreement (as amended, the “Credit Agreement”) is a committed senior unsecured credit facility that includes a revolving credit facility.

On July 8, 2016, the Company entered into Amendment No. 2 to Credit Agreement (“Amendment No. 2”), which amended the Base Credit Agreement to, among other things, make borrowing under the revolving credit facility subject to a borrowing base calculated by reference to the Company’s and certain of its subsidiaries’ eligible equipment, inventory, account receivable and unencumbered cash as described in Amendment No. 2. The revolving credit facility contains a letter of credit facility that is limited to $50 million and a swing line facility that is limited to $20 million, in each case outstanding at any time. The maturity date under the Base Credit Agreement is September 27, 2017 for the revolving facility; however, Amendment No. 2 extended the maturity date of $357.9 million in revolving credit commitments of certain lenders to March 27, 2019. On January 17, 2017, the Company entered into Amendment No. 3 to Credit Agreement, which amended the Credit Agreement by restating the definition of Consolidated EBITDA to provide for the add-back of transaction expenses related to the SSE merger. On January 24, 2017, the Company entered into an agreement with certain lenders under its revolving credit facility to increase the aggregate commitments under its revolving credit facility to approximately $595.8 million, subject to the satisfaction of certain conditions. The aggregate commitment increase became effective on April 20, 2017 upon the consummation of the SSE merger and the repayment and termination of the SSE credit facility. On April 20, 2017, the Company entered into Amendment No. 4 to Credit Agreement which permitted outstanding letters of credit under the SSE credit facility to be deemed to be incurred under the Company’s credit facility and increased the amount of the accordion feature of the Company’s revolving credit facility to permit aggregate commitments to be increased to an amount not to exceed $700 million (subject to satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders). On April 20, 2017, the Company also entered into an additional commitment increase agreement with certain of its lenders pursuant to which total commitments available under the Company’s revolving credit facility (after giving effect to both commitment increases) increased to $632 million through September 2017 and to $490 million through March 2019.

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. Until September 27, 2017, the applicable margin on LIBOR rate loans varies from 2.75% to 3.25% and the applicable margin on base rate loans varies from 1.75% to 2.25%, in each case determined based upon the Company’s debt to capitalization ratio. As of June 30, 2017, the applicable margin on LIBOR rate loans was 2.75% and the applicable margin on base rate loans was 1.75%. Based on the Company’s debt to capitalization ratio at March 31, 2017, the applicable margin on LIBOR loans is 2.75% and the applicable margin on base rate loans is 1.75% as of July 1, 2017. Beginning September 27, 2017, the applicable margin on LIBOR rate loans varies from 3.25% to 3.75% and the applicable margin on base rate loans varies from 2.25% to 2.75%, in each case determined based on the Company’s excess availability under the revolving credit facility. 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 revolving credit facility is 0.50%.

Each domestic subsidiary of the Company unconditionally guarantees all existing and future indebtedness and liabilities of the other guarantors and the Company arising under the Credit Agreement, other than (a) Ambar Lone Star Fluid Services LLC, (b) domestic subsidiaries that directly or indirectly have no material assets other than equity interests in, or capitalization indebtedness owed by, foreign subsidiaries, and (c) any subsidiary having total assets of less than $1 million. Such guarantees also cover obligations of the Company and any subsidiary of the Company arising under any interest rate swap contract with any person while such person is a lender or an affiliate of 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 40%. 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 its 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, 2017.

The Credit Agreement limits the Company’s ability to make investments in foreign subsidiaries or joint ventures such that, if the book value of all such investments since September 27, 2012 is above 20% of the total consolidated book value of the assets of the Company and its subsidiaries on a pro forma basis, the Company will not be able to make such investment. The Credit Agreement also restricts the Company’s ability to pay dividends and make equity repurchases, subject to certain exceptions, including an exception allowing such restricted payments if, before and immediately after giving effect to such restricted payment, the Pro Forma Debt Service Coverage Ratio (as defined in the Credit Agreement) is at least 1.50 to 1.00. In addition, the Credit Agreement requires that, if the consolidated cash balance of the Company and its subsidiaries, subject to certain exclusions, is more than $100 million at the end of the day on which a borrowing is made, the Company can only use the proceeds from such borrowing to fund acquisitions, capital expenditures and the repurchase of indebtedness, and if such proceeds are not used in such manner within three business days, the Company must repay such unused proceeds on the fourth business day following such borrowings.

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, 2017, the Company had $115 million outstanding under the revolving credit facility at a weighted average interest rate of 4.24%. The Company had $15.6 million in letters of credit outstanding at June 30, 2017 and, as a result, had available borrowing capacity of $502 million at that date.

2015 Reimbursement Agreement — On March 16, 2015, the Company entered into a Reimbursement Agreement (the “Reimbursement Agreement”) with The Bank of Nova Scotia (“Scotiabank”), pursuant to which the Company may from time to time request that Scotiabank issue an unspecified amount of letters of credit. As of June 30, 2017, the Company had $39.7 million in letters of credit outstanding under the Reimbursement Agreement.

Under the terms of the Reimbursement Agreement, the Company will reimburse Scotiabank on demand for any amounts that Scotiabank has disbursed under any letters of credit. Fees, charges and other reasonable expenses for the issuance of letters of credit are payable by the Company at the time of issuance at such rates and amounts as are in accordance with Scotiabank’s prevailing practice. The Company is obligated to pay to Scotiabank interest on all amounts not paid by the Company on the date of demand or when otherwise due at the LIBOR rate plus 2.25% per annum, calculated daily and payable monthly, in arrears, on the basis of a calendar year for the actual number of days elapsed, with interest on overdue interest at the same rate as on the reimbursement amounts.

The Company has also agreed that if obligations under the Credit Agreement are secured by liens on any of its or any of its subsidiaries’ property, then the Company’s reimbursement obligations and (to the extent similar obligations would be secured under the Credit Agreement) other obligations under the Reimbursement Agreement and any letters of credit will be equally and ratably secured by all property subject to such liens securing the Credit Agreement.

Pursuant to a Continuing Guaranty dated as of March 16, 2015, the Company’s payment obligations under the Reimbursement Agreement are jointly and severally guaranteed as to payment and not as to collection by subsidiaries of the Company that from time to time guarantee payment under the Credit Agreement.

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 pays 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 pays 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 subsidiaries that are not required to be guarantors under the Credit Agreement.

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 its 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. The Company was in compliance with these covenants at June 30, 2017.

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.

Commitment Letter – On December 12, 2016, in connection with execution of the merger agreement, the Company entered into a financing commitment letter (the “Commitment Letter”) with Canyon Capital Advisors LLC for a senior unsecured bridge facility in an aggregate principal amount not to exceed $150 million (the “Bridge Facility”), for the purposes of repaying or redeeming certain of SSE and its subsidiaries’ indebtedness and to pay related fees and expenses. The Company did not utilize the Bridge Facility prior to the SSE merger closing on April 20, 2017, and the Commitment Letter terminated on the closing date of the SSE merger.

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 $710,000 and $746,000 for the three months ended June 30, 2017 and 2016, respectively, and $1.3 million and $1.5 million for the six months ended June 30, 2017 and 2016, respectively.

Presented below is a schedule of the principal repayment requirements of long-term debt as of June 30, 2017 (in thousands):

Year ending December 31,
2017	$	—
2018		—
2019		115,000
2020		300,000
2021		—
Thereafter		300,000
Total	$	715,000

11. Commitments and Contingencies

As of June 30, 2017, the Company maintained letters of credit in the aggregate amount of $55.2 million for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under the terms of the underlying insurance contracts. These letters of credit expire annually at various times during the year and are typically renewed. As of June 30, 2017, no amounts had been drawn under the letters of credit.

As of June 30, 2017, the Company had commitments to purchase approximately $160 million of major equipment for its drilling, pressure pumping and oilfield rental tools 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 2017, 2018, 2021 and 2041. As of June 30, 2017, the remaining obligation under these agreements was approximately $90.3 million, of which approximately $3.4 million and $9.5 million relates to purchases required during the remainder of 2017 and 2018, respectively. In the event the required minimum quantities are not purchased during certain periods, the Company could be required to make a liquidated damages payment to the respective vendor for any shortfall.

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.

12. Stockholders’ Equity

Stock Offering – On January 27, 2017, the Company completed an offering of 18.2 million shares of its common stock and raised net proceeds of $472 million. The Company used the net proceeds of the offering to repay SSE’s outstanding indebtedness of approximately $472 million.

Cash Dividends — The Company paid cash dividends during the six months ended June 30, 2017 and 2016 as follows:

2017:	Per Share		Total
			(in thousands)
Paid on March 22, 2017	$	0.02	$	3,326
Paid on June 22, 2017		0.02		4,269
Total cash dividends	$	0.04	$	7,595

2016:	Per Share		Total
			(in thousands)
Paid on March 24, 2016	$	0.10	$	14,712
Paid on June 23, 2016		0.02		2,953
Total cash dividends	$	0.12	$	17,665

On July 26, 2017, the Company’s Board of Directors approved a cash dividend on its common stock in the amount of $0.02 per share to be paid on September 21, 2017 to holders of record as of September 7, 2017. 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 debt agreements 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, 2017, 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.

During the six months ended June 30, 2017, the Company withheld 179,711 shares with respect to employees’ tax withholding obligations upon vesting of restricted shares and 7.989 shares with respect to the exercise of a stock option. These shares were acquired at fair market value pursuant to the terms of the 2014 Plan.

Treasury stock acquisitions during the six months ended June 30, 2017 were as follows (dollars in thousands):

	Shares		Cost
Treasury shares at beginning of period		43,392,617	$	911,094
Purchases pursuant to stock buyback program		5,503		109
Acquisitions pursuant to long-term incentive plan		187,700		3,841
Treasury shares at end of period		43,585,820	$	915,044

On April 20, 2017, pursuant to the merger agreement, the Company acquired all of the issued and outstanding shares of common stock of SSE, in exchange for approximately 46.3 million shares of common stock of the Company.

13. Income Taxes

The Company’s effective income tax rate for the three months ended June 30, 2017 was 37.9%, compared with 36.3% for the three months ended June 30, 2016. For the six months ended June 30, 2017, the effective income tax rate was 37.5%, compared to 35.1% for the six months ended June 30, 2016. The effective income tax rate fluctuates from the U.S. statutory tax rate based on, among other factors, changes in pretax income in countries with varying statutory tax rates, impact of state and local taxes, and other differences related to the recognition of income and expense between U.S. GAAP and tax.

Compared with the second quarter of 2016, the higher effective tax rate for the second quarter of 2017 was primarily related to the impact of share-based payment transactions and non-deductible transaction costs associated with the SSE merger. Compared with the first six months of 2016, the higher effective tax rate for the first six months of 2017 was primarily attributable to the changes in state and local taxes, share-based payment transactions, and non-deductible transaction costs associated with the SSE merger, as well as true-up adjustments of Canadian taxes for tax return filings during the six months ended June 30, 2017. The difference also reflects the impact from lost benefits of previous IRC section 199 deductions due to net operating loss carrybacks filed during the six months ended June 30, 2016.

14. 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 as of June 30, 2017 and December 31, 2016 is set forth below (in thousands):

	June 30, 2017				December 31, 2016
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
4.97% Series A Senior Notes	$	300,000	$	303,396	$	300,000	$	283,534
4.27% Series B Senior Notes		300,000		292,033		300,000		263,194
Total debt	$	600,000	$	595,429	$	600,000	$	546,728

The fair values of the Series A Notes and Series B Notes at June 30, 2017 and December 31, 2016 are based on discounted cash flows associated with the respective notes using current market rates of interest at those respective dates. For the Series A Notes, the current market rates used in measuring this fair value were 4.59% at June 30, 2017 and 6.65% at December 31, 2016. For the Series B Notes, the current market rates used in measuring this fair value were 4.88% at June 30, 2017 and 7.02% at December 31, 2016. 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.

15. Recently Issued Accounting Standards

In May 2014, the Financial Accounting Standards Board (“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, 2017. The Company expects to adopt this new revenue guidance utilizing the retrospective method of adoption in the first quarter of 2018, and because the Company is still evaluating the portion of its revenues that will be subject to the new leasing guidance discussed below, it is unable to quantify the impact that the new revenue standard will have on the Company’s consolidated financial statements upon adoption.

In February 2016, the FASB issued an accounting standards update to provide guidance for the accounting for leasing transactions. The requirements in this update are effective during interim and annual periods beginning after December 15, 2018. Since a portion of the Company’s contract drilling revenue will be subject to this new leasing guidance, the Company expects to adopt this updated leasing guidance at the same time its adopts the new revenue standard discussed above, utilizing the retrospective method of adoption. Upon adoption of these two new standards, the Company expects to have a lease component and a service component of revenue related to the Company’s drilling contracts. The Company is still evaluating the impact of this new guidance on its consolidated financial statements. This new leasing guidance will also impact the Company in situations where it is the lessee, and in certain circumstances it will have a right-of-use asset and lease liability on its consolidated financial statements. The Company has not quantified the impact of this guidance to such situations.

In November 2015, the FASB issued an accounting standards update to provide guidance for the presentation of deferred tax liabilities and assets. Under this guidance, for a particular tax-paying component of an entity and within a particular tax jurisdiction, all deferred tax liabilities and assets, as well as any related valuation allowance, shall be offset and presented as a single noncurrent amount. This guidance became effective for the Company during the three months ended March 31, 2017. The adoption of this update was applied retrospectively, resulting in the retroactive adjustment of current deferred tax assets, net and deferred tax liabilities, net as of December 31, 2016. The adoption did not have a material impact on the Company’s consolidated financial statements.

In March 2016, the FASB issued an accounting standards update to provide guidance for the accounting for share-based payment transactions, including the related income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This guidance became effective for the Company during the three months ended March 31, 2017. The Company believes this guidance will cause volatility in its effective tax rates and diluted earnings per share due to the tax effects related to share-based payments being recorded in the statement of operations. The volatility in future periods will depend on the Company’s stock price and the number of shares that vest in the case of restricted stock, restricted stock units and performance stock units, or the number of shares that are exercised in the case of stock options.

In August 2016, the FASB issued an accounting standards update to clarify the presentation of cash receipts and payments in specific situations on the statement of cash flows. The requirements in this update are effective during interim and annual periods in fiscal years beginning after December 15, 2017. The adoption of this update is not expected to have a material impact on the Company’s consolidated financial statements.

In January 2017, the FASB issued an accounting standards update to eliminate Step 2 from the goodwill impairment test. An entity will now perform its annual or interim goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value, but the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. The requirements in this update are effective during interim and annual periods in fiscal years beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates on or after January 1, 2017. The Company adopted this update in 2017 which did not have a material impact on the Company’s consolidated financial statements.

In May 2017, the FASB issued an accounting standards update that provided clarity on which changes to the terms or conditions of share-based payment awards require an entity to apply modification accounting provisions. The requirements in this update are effective during interim and annual periods in fiscal years beginning after December 15, 2017. The adoption of this update is not expected to have a material impact on the Company’s consolidated financial statements.

SPECIAL NOTE 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”), 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; rig counts, source and sufficiency of funds required for building new equipment, upgrading existing equipment and additional acquisitions (if opportunities arise); impact of inflation; demand for our services; competition; equipment availability; government regulation; debt service obligations; and other matters. Our forward-looking statements can be identified by the fact that they do not relate strictly to historical or current facts and often use words such as “anticipate,” “believe,” “budgeted,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “predict”, “potential”, “project,” “pursue,” “should,” “strategy,” “target,” or “will,” 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.

On April 20, 2017, we completed our previously announced merger with Seventy Seven Energy Inc. (“SSE”), pursuant to which a subsidiary of ours was merged with and into SSE, with SSE continuing as the surviving entity and one of our wholly owned subsidiaries (the “SSE merger”). These forward-looking statements include, without limitation, our expectations with respect to:

•

synergies, costs and other anticipated financial impacts of the SSE merger;

•future financial and operating results of the combined company; and

•the combined company’s plans, objectives, expectations and intentions with respect to future operations and services.

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. These forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from actual future results expressed or implied by the forward-looking statements. These risks and uncertainties also include those set forth under “Risk Factors,” in Item 1A of Part II of this Report, as well, as among others, risks and uncertainties relating to:

•

the diversion of management time on merger-related issues;

•

the ultimate timing, outcome and results of integrating our operations with those of SSE;

•

the effects of our business combination with SSE, including the combined company’s future financial condition, results of operations, strategy and plans;

•

potential adverse reactions or changes to business relationships resulting from the SSE merger;

•

expected benefits from the SSE merger and our ability to realize those benefits;

•

the results of merger-related litigation, settlements and investigations;

•

availability of capital and the ability to repay indebtedness when due;

•

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;

•

loss of key customers;

•

utilization, margins and planned capital expenditures;

•

interest rate volatility;

•

compliance with covenants under our debt agreements;

•

excess availability of land drilling rigs and pressure pumping equipment, including as a result of reactivation or construction;

•

equipment specialization and new technologies;

•

operating hazards attendant to the oil and natural gas business;

•

failure by customers to pay or satisfy their contractual obligations (particularly with respect to fixed-term contracts);

•

difficulty in building and deploying new equipment;

•

expansion and development trends of the oil and natural gas industry;

•

weather;

•

shortages, delays in delivery, and interruptions in supply, of equipment and materials;

•

the ability to retain management and field personnel;

•

the ability to effectively identify and enter new markets;

•

the ability to realize backlog;

•

strength and financial resources of competitors;

•

environmental risks and ability to satisfy future environmental costs;

•

global economic conditions;

•

adverse oil and natural gas industry conditions;

•

adverse credit and equity market conditions;

•

operating costs;

•

competition and demand for our services;

•

liabilities from operations for which we do not have and receive full indemnification or insurance;

•

governmental regulation;

•

ability to obtain insurance coverage on commercially reasonable terms;

•

financial flexibility;

•

legal proceedings; and

•

other financial, operational and legal risks and uncertainties detailed from time to time in our filings with the U.S. Securities and Exchange Commission (the “SEC”).

We caution that the foregoing list of factors is not exhaustive. Additional information concerning these and other risk factors is contained in our Annual Report on Form 10-K for the year ended December 31, 2016, our Quarterly Report on Form 10-Q for the three months ended March 31, 2017 and other SEC filings. You are cautioned not to place undue reliance on any of our forward-looking statements. The forward-looking statements speak only as of the date made and, other than as required by law, we undertake no obligation to update publicly or revise any of these forward-looking statements, whether as a result of new information, future events or otherwise. In the event that we update any forward-looking statement, no inference should be made that we will make additional updates with respect to that statement, related matters or any other forward-looking statements. All subsequent written and oral forward-looking statements concerning us, the SSE merger or other matters and attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements above.

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

Recent Developments — On December 12, 2016, we entered into an Agreement and Plan of Merger (the “merger agreement”) with Seventy Seven Energy Inc. (“SSE”). On April 20, 2017, pursuant to the merger agreement, a subsidiary of ours was merged with and into SSE, with SSE continuing as the surviving entity and one of our wholly owned subsidiaries (the “SSE merger”). Pursuant to the terms of the merger agreement, we acquired all of the issued and outstanding shares of common stock of SSE, in exchange for approximately 46.3 million shares of our common stock. Concurrent with the closing of the merger, we repaid all of the outstanding debt of SSE totaling $472 million. Based on the closing price of our common stock on April 20, 2017, the total fair value of the consideration transferred to effect the acquisition of SSE was approximately $1.5 billion. On April 20, 2017, following the SSE merger, SSE was merged with and into our newly-formed subsidiary named Seventy Seven Energy LLC (“SSE LLC”), with SSE LLC continuing as the surviving entity and one of our wholly owned subsidiaries.

Through the SSE merger, we have acquired a fleet of 91 drilling rigs, 36 of which we consider to be APEX® class rigs. Additionally, through the SSE merger, we have acquired approximately 500,000 horsepower of modern, efficient fracturing equipment located in Oklahoma and Texas. The oilfield rentals business acquired through the SSE merger has a modern, well-maintained fleet of premium rental tools, and provides specialized services for land-based oil and natural gas drilling, completion and workover activities. Operational data in the discussion and analysis below includes the results of operations of the SSE business since April 20, 2017.

On January 27, 2017, we completed an offering of 18.2 million shares of our common stock and raised net proceeds of $472 million. We used the net proceeds of the offering to repay SSE’s outstanding indebtedness of approximately $472 million.

On January 24, 2017, we entered into an agreement with certain lenders under our revolving credit facility to increase the aggregate commitments under our revolving credit facility to approximately $595.8 million, subject to the satisfaction of certain conditions. The aggregate commitment increase became effective on April 20, 2017 upon the consummation of the SSE merger and the repayment and termination of the SSE credit facility. On April 20, 2017, we entered into Amendment No. 4 to Credit Agreement which permitted outstanding letters of credit under the SSE credit facility to be deemed to be incurred under our credit facility and increased the amount of the accordion feature of our revolving credit facility to permit aggregate commitments to be increased to an amount not to exceed $700 million (subject to satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders). On April 20, 2017, we also entered into an additional commitment increase agreement with certain of our lenders pursuant to which total commitments available under our revolving credit facility (after giving effect to both commitment increases) increased to $632 million through September 2017 and to $490 million through March 2019.

The closing price of oil was as high as $107.95 per barrel in June 2014. Prices began to fall in the third quarter of 2014 and reached a twelve-year low of $26.19 in February 2016. Oil and natural gas prices have recovered substantially from the lows experienced in the first quarter of 2016. During the fourth quarter of 2016, the Organization of Petroleum Exporting Countries (“OPEC”) and certain non-OPEC countries, including Russia, announced an agreement to cut oil production, resulting in an increase in oil prices, which averaged $51.97 per barrel in December 2016. Oil prices averaged $48.25 per barrel in the second quarter of 2017.

Our rig count in the United States declined significantly during the industry downturn that began in late 2014, but had steadily improved on a monthly basis from May 2016 to June 2017. For the second quarter of 2017, our average rig count improved to 145 rigs in the United States, which was an increase from an average of 81 rigs in the first quarter of 2017 and includes the impact of rigs from the SSE merger. Our rig count in the United States at June 30, 2017 of 161 rigs was 210% greater than our low of 52 rigs in April 2016 and 25% less than the high of 214 rigs in October 2014. Term contracts have supported our operating rig count during the last three years. Based on contracts currently in place, including for rigs acquired from the SSE merger, we expect an average of 94 rigs operating under term contracts during the third quarter of 2017 and an average of 60 rigs operating under term contracts during the twelve months ending June 30, 2018.

Activity levels in our pressure pumping business have also improved. Looking forward, we expect to see further increases in activity across the industry, especially in the Permian Basin. We reactivated two frac spreads during the second quarter, and we have plans to reactivate two frac spreads late in the third quarter and one frac spread during the fourth quarter. With the addition of these three frac spreads in the back half of 2017, we expect to exit 2017 with 23 active frac spreads and have over 80% of our more than 1.5 million hydraulic fracturing horsepower active.

Management Overview — We are a Houston, Texas-based oilfield services company that primarily owns and operates in the United States one of the largest fleets of land-based drilling rigs and a large fleet of pressure pumping equipment. Our contract drilling business operates in the continental United States and western Canada, and we are pursuing contract drilling opportunities outside of North America. Our pressure pumping and oilfield rental tools businesses operate primarily in Texas and the Mid-Continent and Appalachian regions. We also manufacture and sell pipe handling components and related technology to drilling contractors in North America and other select markets. In addition, we own and invest, as a non-operating working interest owner, in oil and natural gas assets that are primarily located in Texas and New Mexico.

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, 2017, our rig fleet included 198 APEX^® class rigs. We expect to add one new APEX^® rig to our fleet during the remainder of 2017. We also plan to upgrade at least seven of our APEX 1000^® rigs to APEX-XK 1500^® rigs

In connection with the development of horizontal shale and other unconventional resource plays, we have added equipment to perform service intensive fracturing jobs. As of June 30, 2017, we had approximately 1.6 million hydraulic horsepower in our pressure pumping fleet (approximately 1.5 million of which was hydraulic fracturing horsepower). We have increased the horsepower of our pressure pumping fleet by more than thirteen-fold since the beginning of 2009. In recent years, the industry-wide addition of new pressure pumping equipment to the marketplace and lower oil and natural gas prices have 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 contract drilling backlog as of June 30, 2017 was approximately $535 million. Approximately 15% of the total June 30, 2017 backlog is reasonably expected to remain at June 30, 2018. We generally calculate our backlog by multiplying the dayrate 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 or incurring maintenance and repair time in excess of what is permitted under the drilling contract. In addition, our term drilling contracts are generally subject to termination by the customer on short notice and provide for an early termination payment to us in the event the contract is terminated by the customer. For contracts on which we have received an early termination notice, our backlog calculation includes the early termination rate, instead of the dayrate, for the period over which we expect to receive the lower rate.

For the three and six months ended June 30, 2017 and 2016, our operating revenues consisted of the following (in thousands):

	Three Months Ended June 30,								Six Months Ended June 30,
	2017				2016				2017				2016
Contract drilling	$	270,111	46.6	%	$	115,235	59.4	%	$	428,839	48.5	%	$	283,894	61.3	%
Pressure pumping		290,044	50.1	%		73,950	38.2	%		431,218	48.8	%		170,263	36.8	%
Other operations		19,031	3.3	%		4,722	2.4	%		24,304	2.7	%		8,689	1.9	%
	$	579,186	100.0	%	$	193,907	100.0	%	$	884,361	100.0	%	$	462,846	100.0	%

Generally, the profitability of our business has been 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 2017, our average number of rigs operating was 145 in the United States and one in Canada, compared to 55 in the United States and less than one in Canada in the second quarter of 2016. Our average revenue per operating day was $20,270 in the second quarter of 2017, compared to $23,070 in the second quarter of 2016. The profitability of our pressure pumping segment has been impacted most by our number of fracturing jobs and our average revenue per fracturing job. We had 173 fracturing jobs during the second quarter of 2017, compared to 74 fracturing jobs during the second quarter of 2016. Our average revenue per fracturing job was $1.643 million in the second quarter of 2017 and $976,300 in the second quarter of 2016. Our margin from contract drilling improved by $38.0 million and our margin from pressure pumping improved by $51.7 million, compared to the second quarter of 2016. These improvements in margin were offset by merger and integration expenses of $51.2 million and an increase in depreciation, depletion, amortization and impairment of $48.4 million. Our consolidated net loss for the second quarter of 2017 was $92.2 million, compared to a consolidated net loss of $85.9 million for the second quarter of 2016.

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. While we have seen recent improvement, there continues to be uncertainty with respect to the global economic environment, and oil and natural gas prices and our monthly average number of rigs operating remain significantly below levels in 2014. Our average number of rigs operating was 160 in the United States and one in Canada in June 2017 and 159 in the United States and three in Canada in July 2017.

We are also 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 II of this Report, in Part I of our Annual Report on Form 10-K for the fiscal year ended December 31, 2016, and in Part II of our Quarterly Report on Form 10-Q for the three months ended March 31, 2017.

Our liquidity as of June 30, 2017 included approximately $98.9 million in working capital, including $40.1 million of cash and cash equivalents, and $502 million available under our revolving credit facility. As of June 30, 2017, we had $115 million outstanding under our revolving credit facility.

We believe our current liquidity, together with cash expected to be generated from operations, should provide us with sufficient ability to fund our current plans to maintain and make improvements to our existing equipment, service our debt, pay cash dividends and finance working capital requirements during a recovery. If under current market conditions we desire to pursue opportunities for growth that require additional capital, we believe such pursuit would likely require additional debt or equity financing. However, there can be no assurance that such capital will be available on reasonable terms, if at all.

Commitments and Contingencies — As of June 30, 2017, we maintained letters of credit in the aggregate amount of $55.2 million for the benefit of various insurance companies as collateral for 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, 2017, no amounts had been drawn under the letters of credit.

As of June 30, 2017, we had commitments to purchase approximately $160 million of major equipment for our drilling, pressure pumping and oilfield rental tools businesses.

Our pressure pumping business has entered into agreements to purchase minimum quantities of proppants and chemicals from certain vendors. These agreements expire in 2017, 2018, 2021 and 2041. As of June 30, 2017, the remaining obligation under these agreements was approximately $90.3 million, of which approximately $3.4 million and $9.5 million relates to purchases required during the remainder of 2017 and 2018, respectively. In the event the required minimum quantities are not purchased during certain periods, we could be required to make a liquidated damages payment to the respective vendor for any shortfall.

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 are a Houston, Texas-based oilfield services company that primarily owns and operates in the United States one of the largest fleets of land-based drilling rigs and a large fleet of pressure pumping equipment. Our contract drilling business operates in the continental United States and western Canada, and we are pursuing contract drilling opportunities outside of North America. Our pressure pumping and oilfield rental tools businesses operate primarily in Texas and the Mid-Continent and Appalachian regions. We also manufacture and sell pipe handling components and related technology to drilling contractors in North America and other select markets. In addition, we own and invest, as a non-operating working interest owner, in oil and natural gas assets that are primarily located 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. The North American oil and natural gas services industry has recently experienced a severe downturn; however, in response to improved commodity prices, U.S. rig counts increased through the first half of 2017.

Construction of new technology drilling rigs increased significantly in the years preceding the recent industry downturn. 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 led to higher demand for pressure pumping services, and there was a significant increase in the construction of new pressure pumping equipment across the industry. As a result of the decline in oil and natural gas prices and the construction of new equipment, there is an excess of drilling rigs and pressure pumping equipment available. In circumstances of excess capacity, providers of drilling and 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.

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. Additionally, in response to customer demand, we are upgrading seven of our APEX 1000^® rigs to APEX-XK 1500^® rigs. 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 drilling rigs,

•

refurbishment and upgrades of existing drilling rigs, or

•

construction of new technology drilling rigs.

Critical Accounting Policies

In addition to established accounting policies, our condensed consolidated financial statements are impacted by certain estimates and assumptions made by management. No changes in our critical accounting policies have occurred since the filing of our Annual Report on Form 10-K for the fiscal year ended December 31, 2016.

We evaluate the recoverability of our long-lived assets whenever events or changes in circumstances indicate that their carrying amounts may not be recoverable (a “triggering event”). Based on recent commodity prices, our results of operations for the three month period ended June 30, 2017, and our expectations of results of operations in future periods, we concluded that no triggering event occurred during the three months ended June 30, 2017 with respect to our contract drilling segment or our pressure pumping segment. Our expectations of results of operations in future periods were based on the assumption that activity levels in both segments will continue to improve throughout 2017 in response to relatively stable oil prices.

We review our proved oil and natural gas properties for impairment whenever a triggering event occurs, such as downward revisions in reserve estimates or decreases in expected future oil and natural gas prices. Proved properties are grouped by field and undiscounted cash flow estimates are prepared based on our expectation of future pricing over the lives of the respective fields. These cash flow estimates are reviewed by an independent petroleum engineer. If the net book value of a field exceeds its undiscounted cash flow estimate, impairment expense is measured and recognized as the difference between net book value and fair value. The fair value estimates used in measuring impairment are based on internally developed unobservable inputs including reserve volumes and future production, pricing and operating costs (Level 3 inputs in the fair value hierarchy of fair value accounting). The expected future net cash flows are discounted using an annual rate of 10% to determine fair value. We review unproved oil and natural gas properties quarterly to assess potential impairment. Our impairment assessment is made on a lease-by-lease basis and considers factors such as our intent to drill, lease terms and abandonment of an area. If an unproved property is determined to be impaired, the related property costs are expensed. Impairment expense related to proved and unproved oil and natural gas properties totaled $1.7 million in the second quarter of 2017 and $2.2 million in the six months ended June 30, 2017 and is included in depreciation, depletion, amortization and impairment in the condensed consolidated statements of operations.

Liquidity and Capital Resources

Our liquidity as of June 30, 2017 included approximately $98.9 million in working capital, including $40.1 million of cash and cash equivalents, and $502 million available under our revolving credit facility. As of July 31, 2017, under our revolving credit facility we had $140 million outstanding, had $15.6 million of letters of credit outstanding, and had borrowing capacity of $477 million.

On January 27, 2017, we completed an offering of 18.2 million shares of our common stock and raised net proceeds of $472 million. We used the net proceeds of the offering to repay of SSE’s outstanding indebtedness of approximately $472 million.

During the six months ended June 30, 2017, our sources of cash flow included:

•

$15.4 million from operating activities,

•

$35.0 million in proceeds from the disposal of property and equipment,

•

$115 million in net borrowings under our revolving credit facility, and

•

$472 million from net proceeds from common stock issuance.

During the six months ended June 30, 2017, we used $434 million for the acquisition of SSE, $7.6 million to pay dividends on our common stock, $3.7 million for treasury stock and $187 million:

•

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

•

to acquire and procure equipment and facilities to support our drilling, pressure pumping, oilfield rental tools and manufacturing operations, 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, 2017 as follows:

	Per Share		Total
			(in thousands)
Paid on March 22, 2017	$	0.02	$	3,326
Paid on June 22, 2017		0.02		4,269
Total cash dividends	$	0.04	$	7,595

On July 26, 2017, our Board of Directors approved a cash dividend on our common stock in the amount of $0.02 per share to be paid on September 21, 2017 to holders of record as of September 7, 2017. However, 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 our debt agreements 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, 2017, we had remaining authorization to purchase approximately $187 million of our outstanding common stock under the 2013 stock buyback program. Shares purchased under a buyback program are accounted for as treasury stock.

Treasury stock acquisitions during the six months ended June 30, 2017 were as follows (dollars in thousands):

	Shares		Cost
Treasury shares at beginning of period		43,392,617	$	911,094
Purchases pursuant to stock buyback program		5,503		109
Acquisitions pursuant to long-term incentive plan		187,700		3,841
Treasury shares at end of period		43,585,820	$	915,044

2012 Credit Agreement — On September 27, 2012, we entered into a Credit Agreement (the “Base Credit Agreement”). The Base Credit Agreement (as amended, the “Credit Agreement”) is a committed senior unsecured credit facility that includes a revolving credit facility.

On July 8, 2016, we entered into Amendment No. 2 to Credit Agreement (“Amendment No. 2”), which amended the Base Credit Agreement to, among other things, make borrowing under the revolving credit facility subject to a borrowing base calculated by reference to our and certain of our subsidiaries’ eligible equipment, inventory, accounts receivable and unencumbered cash as described in Amendment No. 2. The revolving credit facility contains a letter of credit facility that is limited to $50 million and a swing line facility that is limited to $20 million, in each case outstanding at any time. The maturity date under the Base Credit Agreement is September 27, 2017 for the revolving facility; however, Amendment No. 2 extended the maturity date of $357.9 million

in revolving credit commitments of certain lenders to March 27, 2019. On January 17, 2017, we entered into Amendment No. 3 to Credit Agreement, which amended the Credit Agreement by restating the definition of Consolidated EBITDA to provide for the add-back of transaction expenses related to the SSE merger. On January 24, 2017, we entered into an agreement with certain lenders under our revolving credit facility to increase the aggregate commitments under our revolving credit facility to approximately $595.8 million, subject to the satisfaction of certain conditions. The aggregate commitment increase became effective on April 20, 2017 upon the consummation of the SSE merger and the repayment and termination of the SSE credit facility. On April 20, 2017, we entered into Amendment No. 4 to Credit Agreement which permitted outstanding letters of credit under the SSE credit facility to be deemed to be incurred under our credit facility and increased the amount of the accordion feature of our revolving credit facility to permit aggregate commitments to be increased to an amount not to exceed $700 million (subject to satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders). On April 20, 2017, we also entered into an additional commitment increase agreement with certain of our lenders pursuant to which total commitments available under our revolving credit facility (after giving effect to both commitment increases) increased to $632 million through September 2017 and to $490 million through March 2019.

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. Until September 27, 2017, the applicable margin on LIBOR rate loans varies from 2.75% to 3.25% and the applicable margin on base rate loans varies from 1.75% to 2.25%, in each case determined based upon our debt to capitalization ratio. As of June 30, 2017, the applicable margin on LIBOR rate loans was 2.75% and the applicable margin on base rate loans was 1.75%. Based on our debt to capitalization ratio at March 31, 2017, the applicable margin on LIBOR loans is 2.75% and the applicable margin on base rate loans is 1.75% as of July 1, 2017. Beginning September 27, 2017, the applicable margin on LIBOR rate loans varies from 3.25% to 3.75% and the applicable margin on base rate loans varies from 2.25% to 2.75%, in each case determined based on our excess availability under the revolving credit facility. 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 revolving credit facility is 0.50%.

Each of our domestic subsidiaries unconditionally guarantees all existing and future indebtedness and liabilities of the other guarantors and us arising under the Credit Agreement, other than (a) Ambar Lone Star Fluid Services LLC, (b) domestic subsidiaries that directly or indirectly have no material assets other than equity interests in, or capitalization indebtedness owed by, foreign subsidiaries, and (c) any subsidiary having total assets of less than $1 million. 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 or an affiliate of 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 40%. 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 our 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. We were in compliance with these covenants at June 30, 2017.

The Credit Agreement limits our ability to make investments in foreign subsidiaries or joint ventures such that, if the book value of all such investments since September 27, 2012 is above 20% of our total consolidated book value of the assets on a pro forma basis, we will not be able to make such investment. The Credit Agreement also restricts our ability to pay dividends and make equity repurchases, subject to certain exceptions, including an exception allowing such restricted payments if before and immediately after giving effect to such restricted payment, the Pro Forma Debt Service Coverage Ratio (as defined in the Credit Agreement) is at least 1.50 to 1.00. In addition, the Credit Agreement requires that, if our consolidated cash balance, subject to certain exclusions, is more than $100 million at the end of the day on which a borrowing is made, we can only use the proceeds from such borrowing to fund acquisitions, capital expenditures and the repurchase of indebtedness, and if such proceeds are not used in such manner within three business days, we must repay such unused proceeds on the fourth business day following such borrowings.

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) require us to cash collateralize any outstanding letters of credit.

As of June 30, 2017, we had $115 million outstanding under our revolving credit facility at a weighted average interest rate of 4.24%. We had $15.6 million in letters of credit outstanding at June 30, 2017 and, as a result, had available borrowing capacity of $502 million at that date. As of July 31, 2017, under our revolving credit facility we had $140 million outstanding, had $15.6 million of letters of credit outstanding, and had borrowing capacity of $477 million.

2015 Reimbursement Agreement — On March 16, 2015, we entered into a Reimbursement Agreement (the “Reimbursement Agreement”) with The Bank of Nova Scotia (“Scotiabank”), pursuant to which we may from time to time request that Scotiabank issue an unspecified amount of letters of credit. As of June 30, 2017, we had $39.7 million in letters of credit outstanding under the Reimbursement Agreement.

Under the terms of the Reimbursement Agreement, we will reimburse Scotiabank on demand for any amounts that Scotiabank has disbursed under any letters of credit. Fees, charges and other reasonable expenses for the issuance of letters of credit are payable by us at the time of issuance at such rates and amounts as are in accordance with Scotiabank’s prevailing practice. We are obligated to pay to Scotiabank interest on all amounts not paid on the date of demand or when otherwise due at the LIBOR rate plus 2.25% per annum, calculated daily and payable monthly, in arrears, on the basis of a calendar year for the actual number of days elapsed, with interest on overdue interest at the same rate as on the reimbursement amounts.

We have also agreed that if obligations under the Credit Agreement are secured by liens on any of our subsidiaries’ property, then our reimbursement obligations and (to the extent similar obligations would be secured under the Credit Agreement) other obligations under the Reimbursement Agreement and any letters of credit will be equally and ratably secured by all property subject to such liens securing the Credit Agreement.

Pursuant to a Continuing Guaranty dated as of March 16, 2015 (the “Continuing Guaranty”), our payment obligations under the Reimbursement Agreement are jointly and severally guaranteed as to payment and not as to collection by our subsidiaries that from time to time guarantee payment under the Credit Agreement.

Senior Notes — 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 domestic subsidiaries other than subsidiaries that are not required to be guarantors under the Credit Agreement.

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 our 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, 2017. 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.

Commitment Letter – On December 12, 2016 in connection with the execution of the merger agreement, we entered into a financing commitment letter (the “Commitment Letter”) with Canyon Capital Advisors LLC for a senior unsecured bridge facility in an aggregate principal amount not to exceed $150 million (the “Bridge Facility”), for the purposes of repaying or redeeming certain of SSE and its subsidiaries’ indebtedness and to pay related fees and expenses. We did not utilize the Bridge Facility prior to the SSE merger closing on April 20, 2017, and the Commitment Letter terminated on the closing date of the SSE merger.

Results of Operations

We changed our reporting segment presentation in the fourth quarter of 2016, as we no longer consider our oil and natural gas exploration and production activities to be significant to an understanding of our results. We now present the oil and natural gas exploration and production activities, oilfield rental tool business, pipe handling components and related technology business and Middle East/North Africa business as “Other” and “Corporate” reflects only corporate activities. This change in segment presentation was applied retrospectively to all periods presented herein.

The following tables summarize operations by business segment for the three months ended June 30, 2017 and 2016:

Contract Drilling	2017			2016			% Change
	(Dollars in thousands)
Revenues	$	270,111		$	115,235			134.4	%
Direct operating costs		180,658			63,803			183.1	%
Margin (1)		89,453			51,432			73.9	%
Selling, general and administrative		1,401			1,479			(5.3	)%
Depreciation, amortization and impairment		161,414			120,402			34.1	%
Operating loss	$	(73,362	)	$	(70,449	)		4.1	%
Operating days		13,323			4,996			166.7	%
Average revenue per operating day	$	20.27		$	23.07			(12.1	)%
Average direct operating costs per operating day	$	13.56		$	12.77			6.2	%
Average margin per operating day (1)	$	6.71		$	10.29			(34.8	)%
Average rigs operating		146			55			165.5	%
Capital expenditures	$	71,326		$	16,570			330.5	%

(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.

Revenues and direct operating costs increased primarily due to an increase in operating days. Operating days increased due to a recovery in the oil and natural gas industry and rigs acquired in the SSE merger contributed 4,162 operating days. Depreciation, amortization and impairment increased due to the additional SSE assets and due to a $29.0 million impairment from the write-down of drilling equipment that will have no continuing utility as a result of the upgrade of certain rigs to super-spec capability. Average revenue per operating day decreased during the three months ended June 30, 2017 due to a reduction in early termination revenue and the expiration of higher priced, legacy long-term rig contracts. Early termination revenue for the three months ended June 30, 2017 was $1.5 million, compared to $5.4 million for the same period in 2016. Average direct operating costs per operating day increased as a result of a reduction in the proportion of rigs on standby and an increase in rig reactivation expenses. Capital expenditures increased due to upgrading of equipment and higher maintenance capital expenditures as a result of the increase in operating days.

Pressure Pumping	2017			2016			% Change
	(Dollars in thousands)
Revenues	$	290,044		$	73,950			292.2	%
Direct operating costs		233,900			69,546			236.3	%
Margin (1)		56,144			4,404			1,174.8	%
Selling, general and administrative		3,703			3,029			22.3	%
Depreciation, amortization and impairment		47,805			47,400			0.9	%
Operating income (loss)	$	4,636		$	(46,025	)		(110.1	)%
Fracturing jobs		173			74			133.8	%
Other jobs		338			172			96.5	%
Total jobs		511			246			107.7	%
Average revenue per fracturing job	$	1,643.06		$	976.30			68.3	%
Average revenue per other job	$	17.14		$	9.91			73.0	%
Average revenue per total job	$	567.60		$	300.61			88.8	%
Average direct operating costs per total job	$	457.73		$	282.71			61.9	%
Average margin per total job (1)	$	109.87		$	17.90			513.8	%
Margin as a percentage of revenues (1)		19.4	%		6.0	%		223.3	%
Capital expenditures	$	38,780		$	11,780			229.2	%

(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.

Revenues and direct operating costs during the three months ended June 30, 2017 increased primarily due to an increase in the number and size of fracturing jobs. The total number of jobs increased as a result of the SSE merger and a recovery in the oil and natural gas industry. During the quarter, assets acquired in the SSE merger accounted for 53 fracturing jobs. Average revenue per job increased due to improved pricing and an increase in the size of the jobs. Margin as a percentage of revenues improved due to improvements in pricing and economies of scale as activity levels increased. The increase in capital expenditures was primarily due to investments to reactivate frac spreads and higher maintenance capital expenditures as a result of higher activity.

Other Operations	2017			2016		% Change
	(Dollars in thousands)
Revenues	$	19,031		$	4,722		303.0	%
Direct operating costs		12,671			1,650		667.9	%
Margin (1)		6,360			3,072		107.0	%
Selling, general and administrative		2,803			527		431.9	%
Depreciation, depletion and impairment		8,120			1,805		349.9	%
Operating income (loss)	$	(4,563	)	$	740		(716.6	)%
Capital expenditures	$	8,017		$	1,692		373.8	%

(1)	Margin is defined as revenues less direct operating costs and excludes depreciation, depletion and impairment and selling, general and administrative expenses.

Revenues, direct operating costs, selling, general and administrative expense and depreciation expense from other operations increased primarily as a result of the inclusion of our oilfield rental tool business acquired in the SSE merger on April 20, 2017 and our pipe handling components and related technology business acquired in September 2016. Depreciation, depletion and impairment expense in 2017 includes approximately $1.6 million of oil and natural gas property impairments, whereas no oil and natural gas property impairments were recorded in 2016.

Corporate	2017			2016			% Change
	(Dollars in thousands)
Selling, general and administrative	$	15,571		$	12,052			29.2	%
Merger and integration expenses	$	51,193		$	—		NA
Depreciation	$	1,989		$	1,368			45.4	%
Other operating income:
Net gain on asset disposals	$	(1,807	)	$	(4,822	)		(62.5	)%
Legal settlements, net of insurance reimbursements		1			—		NA
Other operating income	$	(1,806	)	$	(4,822	)		(62.5	)%
Interest income	$	642		$	100			542.0	%
Interest expense	$	9,075		$	10,678			(15.0	)%
Other income	$	131		$	17			670.6	%
Capital expenditures	$	227		$	491			(53.8	)%

Selling, general and administrative expense increased in the three months ended June 30, 2017 due to the additional cost related to SSE’s corporate function. Merger and integration expenses incurred in 2017 are related to the SSE merger. Other operating income includes net gains associated with the disposal of assets related to corporate strategy decisions of the executive management group. Accordingly, the related gains or losses have been excluded from the results of specific segments. Interest income increased due to the proceeds from our stock offering in the first quarter of 2017. Interest expense decreased primarily due to lower debt outstanding between the two periods.

The following tables summarize operations by business segment for the six months ended June 30, 2017 and 2016:

Contract Drilling	2017			2016			% Change
	(Dollars in thousands)
Revenues	$	428,839		$	283,894			51.1	%
Direct operating costs		288,879			144,701			99.6	%
Margin (1)		139,960			139,193			0.6	%
Selling, general and administrative		3,055			3,237			(5.6	)%
Depreciation, amortization and impairment		271,973			241,501			12.6	%
Operating loss	$	(135,068	)	$	(105,545	)		28.0	%
Operating days		20,810			11,653			78.6	%
Average revenue per operating day	$	20.61		$	24.36			(15.4	)%
Average direct operating costs per operating day	$	13.88		$	12.42			11.8	%
Average margin per operating day (1)	$	6.73		$	11.94			(43.6	)%
Average rigs operating		115			64			79.7	%
Capital expenditures	$	115,547		$	28,450			306.1	%

(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.

Revenues and direct operating costs increased primarily due to an increase in operating days. Operating days increased due to a recovery in the oil and natural gas industry and rigs acquired in the SSE merger contributed 4,162 operating days. Depreciation, amortization and impairment increased due to the additional SSE assets and due to a $29.0 million impairment from the write-down of drilling equipment that will have no continuing utility as a result of the upgrade of certain rigs to super-spec capability. Average revenue per operating day decreased during the six months ended June 30, 2017 due to a reduction in early termination revenue and the expiration of higher priced, legacy long-term rig contracts. Early termination revenue for the six months ended June 30, 2017 was $3.5 million, compared to $22.2 million for the same period in 2016. Average direct operating costs per operating day increased as a result of a reduction in the proportion of rigs on standby and an increase in rig reactivation expenses. Capital expenditures increased due to upgrading of equipment and higher maintenance capital expenditures as a result of the increase in operating days.

Pressure Pumping	2017			2016			% Change
	(Dollars in thousands)
Revenues	$	431,218		$	170,263			153.3	%
Direct operating costs		352,913			157,359			124.3	%
Margin (1)		78,305			12,904			506.8	%
Selling, general and administrative		6,505			5,918			9.9	%
Depreciation, amortization and impairment		90,055			96,970			(7.1	)%
Operating loss	$	(18,255	)	$	(89,984	)		(79.7	)%
Fracturing jobs		268			157			70.7	%
Other jobs		620			330			87.9	%
Total jobs		888			487			82.3	%
Average revenue per fracturing job	$	1,575.09		$	1,058.99			48.7	%
Average revenue per other job	$	14.67		$	12.13			20.9	%
Average revenue per total job	$	485.61		$	349.62			38.9	%
Average direct operating costs per total job	$	397.42		$	323.12			23.0	%
Average margin per total job (1)	$	88.18		$	26.50			232.8	%
Margin as a percentage of revenues (1)		18.2	%		7.6	%		139.5	%
Capital expenditures and acquisitions	$	58,193		$	19,332			201.0	%

(1)

Revenues and direct operating costs during the six months ended June 30, 2017 increased primarily due to an increase in the number and size of fracturing jobs. The total number of jobs increased as a result of the SSE merger and a recovery in the oil and natural gas industry. Assets acquired in the SSE merger accounted for 53 fracturing jobs. Average revenue per job increased due to improved pricing and an increase in the size of the jobs. Margin as a percentage of revenues improved due to improvements in pricing and economies of scale as activity levels increased. The increase in capital expenditures was primarily due to investments to reactivate frac spreads and higher maintenance capital expenditures as a result of higher activity.

Other Operations	2017			2016			% Change
	(Dollars in thousands)
Revenues	$	24,304		$	8,689			179.7	%
Direct operating costs		15,930			3,740			325.9	%
Margin (1)		8,374			4,949			69.2	%
Selling, general and administrative		4,596			903			409.0	%
Depreciation, depletion and impairment		10,292			6,537			57.4	%
Operating loss	$	(6,514	)	$	(2,491	)		161.5	%
Capital expenditures	$	12,369		$	3,220			284.1	%

(1)	Margin is defined as revenues less direct operating costs and excludes depreciation, depletion and impairment and selling, general and administrative expenses.

Corporate	2017			2016			% Change
	(Dollars in thousands)
Selling, general and administrative	$	28,174		$	25,001			12.7	%
Merger and integration expenses	$	56,349		$	—		NA
Depreciation	$	3,225		$	2,737			17.8	%
Other operating (income) expense, net:
Net gain on asset disposals	$	(15,367	)	$	(7,267	)		111.5	%
Legal settlements, net of insurance reimbursements		657			1,100			(40.3	)%
Other operating (income) expense, net	$	(14,710	)	$	(6,167	)		138.5	%
Interest income	$	1,048		$	210			399.0	%
Interest expense	$	17,345		$	21,478			(19.2	)%
Other income	$	148		$	33			348.5	%
Capital expenditures	$	681		$	832			(18.1	)%

Selling, general and administration expense increased in the six months ended June 30, 2017 due to the additional cost related to SSE’s corporate function. The merger and integration expenses incurred in 2017 are related to the SSE merger. Other operating income includes net gains associated with the disposal of assets related to corporate strategy decisions of the executive management group. Accordingly, the related gains or losses have been excluded from the results of specific segments. The 2017 period includes a gain of $11.2 million related to the sale of real estate. Interest income increased due to the proceeds from our stock offering in the first quarter of 2017. Interest expense decreased primarily due to lower debt outstanding between the two periods.

Adjusted EBITDA

Adjusted EBITDA is a supplemental financial measure not defined by United States generally accepted accounting principles, or U.S. GAAP. We define Adjusted EBITDA as net income (loss) plus net interest expense, income tax expense (benefit) and depreciation, depletion, amortization and impairment expense (including impairment of goodwill). We present Adjusted EBITDA because we believe it provides to both management and investors additional information with respect to both the performance of our fundamental business activities and our ability to meet our capital expenditures and working capital requirements. Adjusted EBITDA should not be construed as an alternative to the U.S. GAAP measure of net income (loss). Set forth below is a reconciliation of the non-U.S. GAAP financial measure of Adjusted EBITDA to the U.S. GAAP financial measure of net income (loss).

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
	(in thousands)
Net loss	$	(92,184	)	$	(85,866	)	$	(155,723	)	$	(156,369	)
Income tax benefit		(56,354	)		(49,027	)		(93,301	)		(84,457	)
Net interest expense		8,433			10,578			16,297			21,268
Depreciation, depletion, amortization and impairment		219,328			170,975			375,545			347,745
Adjusted EBITDA	$	79,223		$	46,660		$	142,818		$	128,187

Income Taxes

Our effective income tax rate for the three months ended June 30, 2017 was 37.9%, compared with 36.3% for the three months ended June 30, 2016. For the six months ended June 30, 2017, the effective income tax rate was 37.5%, compared to 35.1% for the six months ended June 30, 2016. The effective income tax rate fluctuates from the U.S. statutory tax rate based on, among other factors, changes in pretax income in countries with varying statutory tax rates, impact of state and local taxes, and other differences related to the recognition of income and expense between U.S. GAAP and tax.

Recently Issued Accounting Standards

In May 2014, the Financial Accounting Standards Board (“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, 2017. We expect to adopt this new revenue guidance utilizing the retrospective method of adoption in the first quarter of 2018, and because we are still evaluating the portion of our revenues that will be subject to the new leasing guidance discussed below, we are unable to quantify the impact that the new revenue standard will have on our consolidated financial statements upon adoption.

In February 2016, the FASB issued an accounting standards update to provide guidance for the accounting for leasing transactions. The requirements in this update are effective during interim and annual periods beginning after December 15, 2018. Since a portion of our contract drilling revenue will be subject to this new leasing guidance, we expect to adopt this updated leasing guidance at the same time we adopt the new revenue standard discussed above, utilizing the retrospective method of adoption. Upon adoption of these two new standards, we expect to have a lease component and a service component of revenue related to our drilling contracts. We are still evaluating the impact of this new guidance on our consolidated financial statements. This new leasing guidance will also impact us in situations where we are the lessee, and in certain circumstances we will need to record a right-of-use asset and lease liability on our consolidated financial statements. We have not quantified the impact of this guidance to such situations.

In November 2015, the FASB issued an accounting standards update to provide guidance for the presentation of deferred tax liabilities and assets. Under this guidance, for a particular tax-paying component of an entity and within a particular tax jurisdiction, all deferred tax liabilities and assets, as well as any related valuation allowance, shall be offset and presented as a single noncurrent amount. This guidance became effective for us during the three months ended March 31, 2017. The adoption of this update was applied retrospectively, resulting in retroactive adjustment of our current deferred tax assets, net and deferred tax liabilities, net as of December 31, 2016. This adoption did not have a material impact on our consolidated financial statements.

In March 2016, the FASB issued an accounting standards update to provide guidance for the accounting for share-based payment transactions, including the related income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This guidance became effective for us during the three months ended March 31, 2017. We believe this guidance will cause volatility in our effective tax rates and diluted earnings per share due to the tax effects related to share-based payments being recorded in the statement of operations. The volatility in future periods will depend on our stock price and the number of shares that vest in the case of restricted stock, restricted stock units and performance stock units or the number of shares that are exercised in the case of stock options.

In January 2017, the FASB issued an accounting standards update to eliminate Step 2 from the goodwill impairment test. An entity will now perform its annual or interim goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value, but the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. The requirements in this update are effective during interim and annual periods in fiscal years beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates on or after January 1, 2017. We adopted this update in 2017 which did not have a material impact 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 many factors beyond our control. The closing price of oil was as high as $107.95 per barrel in June 2014. Prices began to fall in the third quarter of 2014 and reached a twelve-year low of $26.19 in February 2016. Oil and natural gas prices have recovered substantially from the lows experienced in the first quarter of 2016. During the fourth quarter of 2016, the Organization of Petroleum Exporting Countries (“OPEC”) and certain non-OPEC countries, including Russia, announced an agreement to cut oil production, resulting in an increase in oil prices, which averaged $51.97 per barrel in December 2016. Oil prices averaged $48.25 per barrel in the second quarter of 2017.

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. Higher oil and natural gas prices do not necessarily result in increased activity because demand for our services is generally driven by our customers’ expectations of future oil and natural gas prices. A decline in demand for oil and natural gas, prolonged low oil or natural gas prices or expectations of decreases in oil and natural gas prices, would likely result in reduced capital expenditures by our customers and decreased demand for our services, which could have a material adverse effect on 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 services.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

As of June 30, 2017, we had exposure to interest rate market risk associated with any borrowings that we had under the Credit Agreement and the Reimbursement Agreement.

As of June 30, 2017, we had $115 million outstanding under our revolving credit facility at a weighted average interest rate of 4.24%. The interest rate on the borrowings outstanding under our revolving credit facility is variable and adjusts at each interest payment date based on our election of LIBOR or the base rate.

Under the Reimbursement Agreement, we will reimburse Scotiabank on demand for any amounts that Scotiabank has disbursed under any letters of credit. We are obligated to pay to Scotiabank interest on all amounts not paid by us on the date of demand or when otherwise due at the LIBOR rate plus 2.25% per annum. As of June 30, 2017, no amounts had been disbursed under any letters of credit.

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, 2017.

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.

We completed the acquisition of SSE on April 20, 2017, and we are integrating SSE into our internal control framework. This integration may lead to changes in our controls in future periods, but management does not expect these changes to materially affect our internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 1. Legal Proceedings

We are party to various legal proceedings arising in the normal course of our business; we do not believe that the outcome of these proceedings, either individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows.

ITEM 1A. Risk Factors

The Loss of Large Customers Could Have a Material Adverse Effect on Our Financial Condition and Results of Operations.

With respect to our consolidated operating revenues in 2016, we received approximately 51% from our ten largest customers, 33% from our five largest customers and 14% from our largest customer. For the three months ended March 31, 2017, the five months ended December 31, 2016, the seven months ended July 31, 2016, and the years ended December 31, 2015, 2014 and 2013, Chesapeake Energy Corporation (“CHK”) and its working interest partners accounted for approximately 53%, 51%, 65%, 70%, 81% and 90% of SSE’s revenues, respectively. For the three and six months ended June 30, 2017, CHK and its working interest partners accounted for approximately 16% and 18% of the pro forma combined revenues of SSE and Patterson-UTI, respectively. We are indirectly subject to the business and financial risks of our customers and could be materially adversely affected by the impact of these risks on our largest customers. The loss of, reduction in business from, or failure to receive payment from, one or more of our largest customers could have a material adverse effect on our business, financial condition, cash flows and results of operations.

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, 2017.

							Approximate Dollar
					Total Number of		Value of Shares
					Shares (or Units)		That May Yet Be
					Purchased as Part		Purchased Under the
	Total		Average Price		of Publicly		Plans or
	Number of Shares		Paid per		Announced Plans		Programs (in
Period Covered	Purchased (2)		Share		or Programs		thousands)(1)
April 2017		14,085	$	22.58		—		186,653
May 2017		2,444	$	21.83		—		186,653
June 2017		168,685	$	19.89		5,503		186,544
Total		185,214				5,503		186,544

(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 14,085 shares in April 2017, 2,444 shares in May 2017 and 163,182 shares in June 2017 with respect to employees’ tax withholding obligations upon vesting of restricted shares. These shares were acquired at fair market value pursuant to the terms of the Patterson-UTI Energy, Inc. 2014 Long-Term Incentive Plan and not pursuant to the stock buyback program.

ITEM 6. Exhibits

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

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

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

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

10.1		Amendment No. 4 to Credit Agreement, dated as of April 20, 2017, by and among Patterson-UTI Energy, Inc., certain subsidiaries of Patterson-UTI Energy, Inc. party thereto, Wells Fargo Bank, N.A., as administrative agent, issuer of letters of credit and swing line lender and the other lenders party thereto (filed April 21, 2017 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference).

10.2		Commitment Increase Agreement, dated as of April 20, 2017, by and among Patterson-UTI Energy, Inc., certain subsidiaries of Patterson-UTI Energy, Inc. party thereto, Wells Fargo Bank, N.A., as administrative agent, issuer of letters of credit and swing line lender and the other lenders party thereto (filed April 21, 2017 as Exhibit 10.2 to the Company’s Current Report on Form 8-K and incorporated herein by reference).

10.3		Patterson-UTI Energy, Inc. Omnibus Incentive Plan (filed April 21, 2017 as Exhibit 4.4 to the Company’s Registration Statement on Form S-8 and incorporated herein by reference).

10.4		Patterson-UTI Energy, Inc. 2014 Long-Term Incentive Plan (as amended and restated effective June 29, 2017) (filed June 30, 2017 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference).

10.5*		Form of Executive Officer Restricted Stock Unit Award Agreement.

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, 2017, formatted in XBRL (Extensible Business Reporting Language): (i) the Condensed Consolidated Balance Sheets, (ii) the Condensed Consolidated Statements of Operations, (iii) the Condensed Consolidated Statements of Comprehensive Income (Loss), (iv) the Condensed Consolidated Statement of Changes in Stockholders’ Equity, (v) the Condensed Consolidated Statements of Cash Flows, and (vi) Notes to Condensed Consolidated 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
		Executive Vice President – Corporate Development,
		Chief Financial Officer and Treasurer
		(Principal Financial and Accounting Officer and Duly Authorized Officer)

Date: August 4, 2017