PATTERSON UTI ENERGY INC - Quarter Report: 2019 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, 2019

☐	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)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class		Trading Symbol		Name of each exchange on which registered
Common Stock, $0.01 Par Value		PTEN		The Nasdaq Global Select Market

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 every Interactive Data File required to be submitted 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 such files). Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth 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.

202,606,846 shares of common stock, $0.01 par value, as of July 25, 2019

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 statements 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	27
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	40
ITEM 4.	Controls and Procedures	40

	PART II — OTHER INFORMATION

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

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,
	2019			2018
ASSETS
Current assets:
Cash and cash equivalents	$	255,514		$	245,029
Accounts receivable, net of allowance for doubtful accounts of $5,901 and $2,312 at June 30, 2019 and December 31, 2018, respectively		501,206			558,817
Federal and state income taxes receivable		5,954			4,110
Inventory		68,611			65,579
Other		66,459			76,662
Total current assets		897,744			950,197
Property and equipment, net		3,769,258			4,002,549
Right of use asset		26,665			—
Goodwill and intangible assets		472,413			477,640
Deposits on equipment purchases		7,312			12,040
Other		18,391			27,440
Total assets	$	5,191,783		$	5,469,866
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	242,166		$	288,962
Federal and state income taxes payable		269			1,408
Accrued liabilities		218,632			235,946
Lease liability		8,977			—
Total current liabilities		470,044			526,316
Long-term lease liability		22,355			—
Long-term debt, net of debt discount and issuance costs of $5,352 and $5,795 at June 30, 2019 and December 31, 2018, respectively		1,119,648			1,119,205
Deferred tax liabilities, net		291,294			306,161
Other		10,131			12,761
Total liabilities		1,913,472			1,964,443
Commitments and contingencies (see Note 10)
Stockholders' equity:
Preferred stock, par value $.01; authorized 1,000,000 shares, no shares issued		—			—
Common stock, par value $.01; authorized 400,000,000 shares with 268,790,705 and 267,315,526 issued and 202,401,130 and 213,614,430 outstanding at June 30, 2019 and December 31, 2018, respectively		2,688			2,673
Additional paid-in capital		2,856,746			2,827,154
Retained earnings		1,658,417			1,753,557
Accumulated other comprehensive income		4,279			2,487
Treasury stock, at cost, 66,389,575 and 53,701,096 shares at June 30, 2019 and December 31, 2018, respectively		(1,243,819	)		(1,080,448	)
Total stockholders' equity		3,278,311			3,505,423
Total liabilities and stockholders' equity	$	5,191,783		$	5,469,866

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,
	2019			2018			2019			2018
Operating revenues:
Contract drilling	$	348,138		$	349,922		$	720,530		$	677,725
Pressure pumping		251,008			425,303			498,609			832,087
Directional drilling		50,218			52,705			103,177			101,321
Other		26,401			26,488			57,620			52,449
Total operating revenues		675,765			854,418			1,379,936			1,663,582
Operating costs and expenses:
Contract drilling		201,792			217,674			420,994			430,257
Pressure pumping		206,137			342,885			408,885			663,855
Directional drilling		42,102			43,685			87,704			81,374
Other		17,612			17,513			39,385			35,258
Depreciation, depletion, amortization and impairment		208,688			212,384			423,098			422,276
Selling, general and administrative		34,894			35,663			67,449			68,480
Provision for bad debts		3,594			—			3,594			—
Merger and integration expenses		—			747			—			2,738
Other operating expenses (income), net		9,071			(7,129	)		335			(9,550	)
Total operating costs and expenses		723,890			863,422			1,451,444			1,694,688
Operating loss		(48,125	)		(9,004	)		(71,508	)		(31,106	)

Other income (expense):
Interest income		1,756			2,360			2,788			3,783
Interest expense, net of amount capitalized		(13,298	)		(12,667	)		(26,282	)		(26,292	)
Other		92			216			209			385
Total other expense		(11,450	)		(10,091	)		(23,285	)		(22,124	)

Loss before income taxes		(59,575	)		(19,095	)		(94,793	)		(53,230	)

Income tax benefit		(10,128	)		(8,382	)		(16,732	)		(8,100	)

Net loss	$	(49,447	)	$	(10,713	)	$	(78,061	)	$	(45,130	)

Net loss per common share:
Basic	$	(0.24	)	$	(0.05	)	$	(0.37	)	$	(0.21	)
Diluted	$	(0.24	)	$	(0.05	)	$	(0.37	)	$	(0.21	)

Weighted average number of common shares outstanding:
Basic		207,499			220,093			209,671			220,436
Diluted		207,499			220,093			209,671			220,436
Cash dividends per common share	$	0.04		$	0.04		$	0.08		$	0.06

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,
	2019			2018			2019			2018
Net loss	$	(49,447	)	$	(10,713	)	$	(78,061	)	$	(45,130	)
Other comprehensive income (loss), net of taxes of $0 for all periods:
Foreign currency translation adjustment		848			(1,530	)		1,792			(3,514	)
Total comprehensive loss	$	(48,599	)	$	(12,243	)	$	(76,269	)	$	(48,644	)

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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS 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, 2018		267,316		$	2,673	$	2,827,154		$	1,753,557		$	2,487	$	(1,080,448	)	$	3,505,423
Net loss		—			—		—			(78,061	)		—		—			(78,061	)
Foreign currency translation adjustment		—			—		—			—			1,792		—			1,792
Exercise of stock options		700			7		9,212			—			—		—			9,219
Vesting of restricted stock units		777			8		(8	)		—			—		—			—
Forfeitures of restricted stock		(2	)		—		—			—			—		—			—
Stock-based compensation		—			—		20,388			—			—		—			20,388
Payment of cash dividends		—			—		—			(16,843	)		—		—			(16,843	)
Dividend equivalents		—			—		—			(236	)		—		—			(236	)
Purchase of treasury stock		—			—		—			—			—		(163,371	)		(163,371	)
Balance, June 30, 2019		268,791		$	2,688	$	2,856,746		$	1,658,417		$	4,279	$	(1,243,819	)	$	3,278,311

												Accumulated
	Common Stock					Additional						Other
	Number of					Paid-in			Retained			Comprehensive			Treasury
	Shares			Amount		Capital			Earnings			Income (Loss)			Stock			Total
Balance, December 31, 2017		266,259		$	2,662	$	2,785,823		$	2,105,897		$	6,822		$	(918,711	)	$	3,982,493
Net loss		—			—		—			(45,130	)		—			—			(45,130	)
Foreign currency translation adjustment		—			—		—			—			(3,514	)		—			(3,514	)
Exercise of stock options		40			1		484			—			—			—			485
Issuance of common stock		381			4		(4	)		—			—			—			—
Vesting of restricted stock units		10			—		—			—			—			—			—
Forfeitures of restricted stock		(2	)		—		—			—			—			—			—
Stock-based compensation		—			—		19,272			—			—			—			19,272
Payment of cash dividends		—			—		—			(13,275	)		—			—			(13,275	)
Dividend equivalents		—			—		—			(113	)		—			—			(113	)
Purchase of treasury stock		—			—		—			—			—			(59,879	)		(59,879	)
Balance, June 30, 2018		266,688		$	2,667	$	2,805,575		$	2,047,379		$	3,308		$	(978,590	)	$	3,880,339

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,
	2019			2018
Cash flows from operating activities:
Net loss	$	(78,061	)	$	(45,130	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, amortization and impairment		423,098			422,276
Dry holes and abandonments		94			562
Deferred income tax benefit		(14,867	)		(8,100	)
Stock-based compensation expense		20,388			19,272
Net gain on asset disposals		(10,516	)		(17,472	)
Writedown of capacity reservation contract		12,673			—
Provision for bad debts		3,594			—
Amortization of debt discount and issuance costs		443			387
Changes in operating assets and liabilities:
Accounts receivable		54,188			(22,363	)
Income taxes receivable/payable		(2,972	)		(22	)
Inventory and other assets		(3,967	)		(25,277	)
Accounts payable		(16,941	)		(23,432	)
Accrued liabilities		(18,884	)		(542	)
Other liabilities		(2,971	)		76
Net cash provided by operating activities		365,299			300,235
Cash flows from investing activities:
Acquisitions, net of cash acquired		(13	)		(3,800	)
Purchases of property and equipment		(215,260	)		(317,783	)
Proceeds from disposal of assets and insurance claims		31,516			21,005
Collection of note receivable		—			23,760
Net cash used in investing activities		(183,757	)		(276,818	)
Cash flows from financing activities:
Purchases of treasury stock		(154,152	)		(59,879	)
Proceeds from exercise of options		—			485
Dividends paid		(16,843	)		(13,275	)
Debt issuance costs		—			(4,333	)
Proceeds from long-term debt		—			521,194
Proceeds from borrowings under revolving credit facility		—			79,000
Repayment of borrowings under revolving credit facility		—			(347,000	)
Net cash provided by financing activities		(170,995	)		176,192
Effect of foreign exchange rate changes on cash		(62	)		(529	)
Net increase in cash and cash equivalents		10,485			199,080
Cash and cash equivalents at beginning of period		245,029			42,828
Cash and cash equivalents at end of period	$	255,514		$	241,908
Supplemental disclosure of cash flow information:
Net cash (paid) received during the period for:
Interest, net of capitalized interest of $380 in 2019 and $722 in 2018	$	(24,924	)	$	(15,573	)
Income taxes		(1,127	)		21
Non-cash investing and financing activities:
Receivable from property and equipment insurance	$	—		$	15,000
Net increase (decrease) in payables for purchases of property and equipment		(29,935	)		75,032
Net (increase) decrease in deposits on equipment purchases		4,728			(5,419	)
Cashless exercise of stock options		9,219			—

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 Presentation

Basis of presentation - The unaudited interim condensed consolidated financial statements include the accounts of Patterson-UTI Energy, Inc. and its wholly-owned subsidiaries (collectively referred to herein as the “Company”). All significant intercompany accounts and transactions have been eliminated. Except for wholly-owned subsidiaries, the Company has no controlling financial interests in any other entity which would require consolidation. As used in these notes, “the Company” refers collectively to Patterson-UTI Energy, Inc. and its consolidated subsidiaries. Patterson-UTI Energy, Inc. conducts its business operations through its wholly-owned subsidiaries and has no employees or independent operations.

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 (“SEC”). 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, 2018, 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, 2018. The results of operations for the three months and six months ended June 30, 2019 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 use the Canadian dollar as their functional currency. The effects of exchange rate changes are reflected in accumulated other comprehensive income, which is a separate component of stockholders’ equity.

Recently Adopted 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 adopted this new revenue guidance effective January 1, 2018, utilizing the modified retrospective method, and expanded its consolidated financial statement disclosures in order to comply with the update (See Note 3). The adoption of this update did not have a material impact on the Company’s consolidated financial statements.

In February 2016, the FASB issued an accounting standards update to provide guidance for the accounting for leasing transactions. The standard requires the lessee to recognize a lease liability along with a right-of-use asset for all leases with a term longer than one year. A lessee is permitted to make an accounting policy election by class of underlying asset to not recognize the lease liability and related right-of-use asset for leases with a term of one year or less. The provisions of this standard also apply to situations where the Company is the lessor. The requirements in this update are effective during interim and annual periods beginning after December 15, 2018. The Company adopted this new leasing guidance effective January 1, 2019 and expanded its consolidated financial statement disclosures in order to comply with the update (See Note 4).

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 on January 1, 2018 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 on January 1, 2018 did not have a material impact on the Company’s consolidated financial statements.

In March 2018, the FASB issued an accounting standards update to update the income tax accounting in U.S. GAAP to reflect the SEC interpretive guidance released on December 22, 2017, when significant U.S. tax law changes were enacted with the enactment of “H.R.1,” also known as the “Tax Cuts and Jobs Act” (“U.S. Tax Reform”). The adoption of this update in March 2018 did not have a material impact on the Company’s consolidated financial statements, as the Company was already following the SEC guidance (See Note 13).

Recently Issued Accounting Standards – In June 2016, the FASB issued an accounting standards update on measurement of credit losses on financial instruments. This update improves financial reporting by requiring earlier recognition of credit losses on financing receivables and other financial assets in scope by using the Current Expected Credit Losses model (CECL). This guidance is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted. The Company is currently evaluating the impact this new guidance will have on its consolidated financial statements.

In August 2018, the FASB issued an accounting standards update to align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The amendments in the update are effective for public business entities for fiscal years beginning after December 15, 2019, with early adoption permitted. The Company is currently evaluating the impact this new guidance will have on its consolidated financial statements.

In August 2018, the FASB issued an accounting standards update to eliminate certain disclosure requirements for fair value measurements for all entities, require public entities to disclose certain new information and modify certain disclosure requirements. The FASB developed the amendments to Topic 820 as part of its broader disclosure framework project, which aims to improve the effectiveness of disclosures in the notes to financial statements by focusing on requirements that clearly communicate the most important information to users of the financial statements. This guidance is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted. The Company is currently evaluating the impact this new guidance will have on its consolidated financial statements.

2. Acquisitions

Superior QC, LLC (“Superior QC”)

On February 20, 2018, the Company acquired the business of Superior QC, including its assets and intellectual property. Superior QC is a provider of software and services used to improve the statistical accuracy of horizontal wellbore placement. Superior QC’s measurement-while-drilling (MWD) survey fault detection, isolation and recovery (FDIR) service is a data analytics technology to analyze MWD survey data in real-time and more accurately identify the position of a well. This acquisition was not material to the Company’s consolidated financial statements.

Current Power Solutions, Inc. (“Current Power”)

On October 25, 2018, the Company acquired Current Power. Current Power is a provider of electrical controls and automation to the energy, marine and mining industries. This acquisition was not material to the Company’s consolidated financial statements.

3. Revenues

ASC Topic 606 Revenue from Contracts with Customers

The Company’s contracts with customers include both long-term and short-term contracts. Services that primarily generate revenue earned for the Company include the operating business segments of contract drilling, pressure pumping and directional drilling, which comprise the Company’s reportable segments. The Company also derives revenues from its other operations, which include the Company’s operating business segments of oilfield rentals, oilfield technology, electrical controls and automation, and oil and natural gas working interests. For more information on the Company’s business segments, including disaggregated revenue recognized from contracts with customers, see Note 15.

Charges for services are considered a series of distinct services. Since each distinct service in a series would be satisfied over time if it were accounted for separately, and the entity would measure its progress towards satisfaction using the same measure of progress for each distinct service in the series, the Company is able to account for these integrated services as a single performance obligation that is satisfied over time.

The transaction price is the amount of consideration to which the Company expects to be entitled in exchange for transferring promised goods or services to a customer, based on terms of the Company’s contracts with its customers. The consideration promised in a contract with a customer may include fixed amounts and/or variable amounts. Payments received for services are considered variable consideration as the time in service will fluctuate as the services are provided. Topic 606 provides an allocation exception, which allows the Company to allocate variable consideration to one or more distinct services promised in a series of distinct services that form part of a single performance obligation as long as certain criteria are met. These criteria state that the variable payment must relate specifically to the entity’s efforts to satisfy the performance obligation or transfer the distinct good or service, and allocation of the variable consideration is consistent with the standards’ allocation objective. Since payments received for services meet both of these criteria requirements, the Company recognizes revenue when the service is performed.

An estimate of variable consideration should be constrained to the extent that it is not probable that a significant revenue reversal in the amount of cumulative revenue recognized will not occur when the uncertainty associated with the variable consideration is subsequently resolved. Payments received for other types of consideration are fully constrained as they are highly susceptible to factors outside the entity’s influence and therefore could be subject to a significant revenue reversal once resolved. As such, revenue received for these types of consideration is recognized when the service is performed.

Estimates of variable consideration are subject to change as facts and circumstances evolve. As such, the Company will evaluate its estimates of variable consideration that are subject to constraints throughout the contract period and revise estimates, if necessary, at the end of each reporting period.

The Company is a working interest owner of oil and natural gas properties located in Texas and New Mexico. The ownership terms are outlined in joint operating agreements for each well between the operator and the various interest owners, including the Company, who are considered non-operators of the well. The Company receives revenue each period for its working interest in the well during the period. The revenue received for the working interests from these oil and gas properties does not fall under the scope of the new revenue standard, and therefore, will continue to be reported under current guidance ASC 932-323 Extractive Activities – Oil and Gas, Investments – Equity Method and Joint Ventures.

Reimbursement Revenue – Reimbursements for the purchase of supplies, equipment, personnel services, shipping and other services that are provided at the request of the Company’s customers are recorded as revenue when incurred. The related costs are recorded as operating expenses when incurred.

Accounts Receivable and Contract Liabilities

Accounts receivable is the Company’s right to consideration once it becomes unconditional. Payment terms typically range from 30 to 60 days.

Accounts receivable balances were $497 million and $554 million as of June 30, 2019 and December 31, 2018, respectively. These balances do not include amounts related to the Company’s oil and gas working interests as those contracts are excluded from Topic 606. Accounts receivable balances are included in “Accounts receivable” in the Condensed Consolidated Balance Sheets.

The Company does not have any significant contract asset balances, and as such, contract balances are not presented at the net amount at a contract level. Contract liabilities include prepayments received from customers prior to the requested services being completed. Once the services are complete and have been invoiced, the prepayment is applied against the customer’s account to offset the accounts receivable balance. Also included in contract liabilities are payments received from customers for the initial mobilization of newly constructed or upgraded rigs that were moved on location to the initial well site. These mobilization payments are allocated to the overall performance obligation and amortized over the initial term of the contract. During the six months ended June 30, 2019 and 2018, approximately $0.8 million and $0.8 million, respectively, was amortized and recorded in drilling revenue.

Contract liability balances for customer prepayments were $4.0 million and $3.0 million as of June 30, 2019 and December 31, 2018, respectively. Contract liability balances for deferred mobilization payments relating to newly constructed or upgraded rigs were $3.9 million and $4.6 million as of June 30, 2019 and December 31, 2018, respectively. Contract liability balances for customer prepayments are included in “Accounts payable” and contract liability balances for deferred mobilization payments are included in “Accrued liabilities” in the Condensed Consolidated Balance Sheets.

Contract Costs

Costs incurred for newly constructed or rig upgrades based on a contract with a customer are considered capital improvements and are capitalized to drilling equipment and depreciated over the estimated useful life of the asset.

4. Leases

ASC Topic 842 Leases

On January 1, 2019, the Company adopted the new lease guidance under Topic 842, Leases, using the modified retrospective approach to each lease that existed at the date of initial application as well as leases entered into after that date. The Company has elected to report all leases at the beginning of the period of adoption and not restate its comparative periods. This standard does not apply to leases to explore for or use minerals, oil, natural gas and similar non-regenerative resources, including the intangible right to explore for those natural resources and rights to use the land in which those natural resources are contained.

The Company has entered into operating leases for operating locations, corporate offices and certain operating equipment. These leases have remaining lease terms of 6 months to 9 years as of June 30, 2019. Currently, the Company does not have any finance leases. The Company has elected the short-term lease recognition practical expedient whereby right of use assets and lease liabilities are not recognized for leasing arrangements with an initial term of one year or less.

Topic 842 requires that lessees and lessors discount lease payments at the lease commencement date using the rate implicit in the lease, if available, or the lessee’s incremental borrowing rate. The Company uses the implicit rate when readily determinable. If the implicit rate is not readily determinable, the Company uses its incremental borrowing rate based on the information available at the commencement date in the determination of the present value of future lease payments.

Practical Expedients Adopted with Topic 842

The Company has elected to adopt the following practical expedients upon the transition date to Topic 842 on January 1, 2019:

•

Transitional practical expedients package: An entity may elect to apply the listed practical expedients as a package to all the leases that commenced before the effective date. The practical expedients are:

	a)	The entity need not reassess whether any expired or existing contracts are or contains leases;
	b)	The entity need not reassess the lease classification for expired or existing contracts;
	c)	The entity need not reassess initial direct costs for any existing leases.

•

Use of portfolio approach: An entity can apply this guidance to a portfolio of leases with similar characteristics if the entity reasonably expects that the application of the leases model to the portfolio would not differ materially from the application of the leases model to the individual leases in that portfolio. This approach can also be applied to other aspects of the leases guidance for which lessees/lessors need to make judgments and estimates, such as determining the discount rate and determining and reassessing the lease term.

•

Lease and non-lease components: As a practical expedient, lease and non-lease components may be combined where the revenue recognition pattern is the same and where the lease component, when accounted for separately, would be considered an operating lease. The Company’s contract drilling, pressure pumping and directional drilling contracts contain a lease component related to the underlying equipment utilized, in addition to the service component provided by the Company’s crews and expertise to operate the related equipment. The Company has concluded that the non-lease service of operating its equipment and providing expertise in the services provided to our customers is predominant in the Company’s drilling, pressure pumping and directional drilling contracts. With the election of this practical expedient, the Company will continue to present a single performance obligation for these contracts under the revenue guidance in ASC 606.

Lease expense consisted of the following for the three and six months ended June 30, 2019 (in thousands):


	Three Months Ended		Six Months Ended
	June 30, 2019		June 30, 2019
Operating lease cost	$	2,755	$	5,794
Short-term lease expense ⁽¹⁾		111		387
Total lease expense	$	2,866	$	6,181

⁽¹⁾	Short-term lease expense represents expense related to leases with a contract term of one year or less.

Supplemental cash flow information related to leases for the six months ended June 30, 2019 is as follows (in thousands):

	Six Months Ended
	June 30, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	5,165

Right of use assets obtained in exchange for lease obligations:
Operating leases	$	627

Supplemental balance sheet information related to leases as of June 30, 2019 is as follows:


	June 30, 2019
Weighted Average Remaining Lease Term:
Operating leases	4.9 years

Weighted Average Discount Rate:
Operating leases		4.5	%

Maturities of operating lease liabilities as of June 30, 2019 are as follows (in thousands):

Year ending December 31,
2019 (excluding the six months ended June 30, 2019)	$	5,268
2020		9,195
2021		6,668
2022		4,625
2023		2,663
Thereafter		6,552
Total lease payments		34,971
Less imputed interest		(3,639	)
Total	$	31,332

Maturities of operating lease liabilities as of December 31, 2018, as previously disclosed in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2018, are as follows (in thousands):

Year ending December 31,
2019	$	11,408
2020		9,069
2021		6,543
2022		4,625
2023		2,663
Thereafter		6,552
Total	$	40,860

5. Inventory

Inventory consisted of the following at June 30, 2019 and December 31, 2018 (in thousands):


	June 30, 2019		December 31, 2018
Finished goods	$	7	$	347
Work-in-process		8,194		6,375
Raw materials and supplies		60,410		58,857
Inventory	$	68,611	$	65,579

6. Property and Equipment

Property and equipment consisted of the following at June 30, 2019 and December 31, 2018 (in thousands):


	June 30, 2019			December 31, 2018
Equipment	$	8,321,611		$	8,370,933
Oil and natural gas properties		220,634			219,855
Buildings		187,958			186,736
Land		26,618			26,144
Total property and equipment		8,756,821			8,803,668
Less accumulated depreciation, depletion and impairment		(4,987,563	)		(4,801,119	)
Property and equipment, net	$	3,769,258		$	4,002,549

The Company reviews its long-lived assets, including property and equipment, for impairment whenever events or changes in circumstances indicate that the carrying amounts of certain assets may not be recovered over their estimated remaining useful lives (“triggering events”). In connection with this review, assets are grouped at the lowest level at which identifiable cash flows are largely independent of other asset groupings. The Company estimates future cash flows over the life of the respective assets or asset groupings in its assessment of impairment. These estimates of cash flows are based on historical cyclical trends in the industry as well as the Company’s expectations regarding the continuation of these trends in the future. Provisions for asset impairment are charged against income when estimated future cash flows, on an undiscounted basis, are less than the asset’s net book value. Any provision for impairment is measured at fair value.

The Company concluded that no triggering events occurred during the six months ended June 30, 2019 with respect to its asset groups based on the Company’s results of operations for the three months and six months ended June 30, 2019, management’s expectations of operating results in future periods and the prevailing commodity prices at the time.

7. Goodwill and Intangible Assets

Goodwill — Goodwill by operating segment as of June 30, 2019 and changes for the six months then ended are as follows (in thousands):

	Contract		Other
	Drilling		Operations		Total
Balance at beginning of period	$	395,060		15,696	$	410,756
Changes to goodwill		—		2,104		2,104
Balance at end of period	$	395,060	$	17,800	$	412,860

The goodwill reflected above in Other Operations has increased primarily as a result of a measurement period adjustment related to accrued liabilities, which resulted in a $2.1 million increase from the original purchase price allocation assessed with the Current Power acquisition. There were no accumulated impairment losses related to goodwill in the contract drilling segment or other operations as of June 30, 2019 or December 31, 2018.

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 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, 2019 and December 31, 2018 (in thousands):

	June 30, 2019							December 31, 2018
	Gross					Net		Gross					Net
	Carrying		Accumulated			Carrying		Carrying		Accumulated			Carrying
	Amount		Amortization			Amount		Amount		Amortization			Amount
Customer relationships	$	28,000	$	(15,214	)		12,786	$	28,000	$	(10,719	)	$	17,281
Developed technology		55,772		(9,321	)		46,451		55,772		(6,533	)		49,239
Favorable drilling contracts		—		—			—		22,500		(22,500	)		—
Internal use software		482		(166	)		316		482		(118	)		364
	$	84,254	$	(24,701	)	$	59,553	$	106,754	$	(39,870	)	$	66,884

Amortization expense on intangible assets of approximately $3.7 million and $4.9 million was recorded in the three months ended June 30, 2019 and 2018, respectively. Amortization expense on intangible assets of approximately $7.3 million and $10.3 million was recorded in the six months ended June 30, 2019 and 2018, respectively.

8. Accrued Liabilities

Accrued liabilities consisted of the following at June 30, 2019 and December 31, 2018 (in thousands):


	June 30, 2019		December 31, 2018
Salaries, wages, payroll taxes and benefits	$	43,832	$	58,160
Workers' compensation liability		74,604		83,772
Property, sales, use and other taxes		34,149		25,318
Insurance, other than workers' compensation		8,844		9,531
Accrued interest payable		16,471		15,774
Other		40,732		43,391
Total	$	218,632	$	235,946

9. Long Term Debt

2018 Credit Agreement — On March 27, 2018, the Company entered into an amended and restated credit agreement (the “Credit Agreement”) among the Company, as borrower, Wells Fargo Bank, National Association, as administrative agent, letter of credit issuer, swing line lender and lender, each of the other lenders and letter of credit issuers party thereto, The Bank of Nova Scotia and U.S. Bank National Association, as Co-Syndication Agents, Royal Bank of Canada, as Documentation Agent and Wells Fargo Securities, LLC, The Bank of Nova Scotia and U.S. Bank National Association, as Co-Lead Arrangers and Joint Book Runners.

The Credit Agreement is a committed senior unsecured revolving credit facility that permits aggregate borrowings of up to $600 million, including a letter of credit facility that, at any time outstanding, is limited to $150 million and a swing line facility that, at any time outstanding, is limited to $20 million. Subject to customary conditions, the Company may request that the lenders’ aggregate commitments be increased by up to $300 million, not to exceed total commitments of $900 million. The original maturity date under the Credit Agreement was March 27, 2023. On March 26, 2019, the Company entered into Amendment No. 1 to Amended and Restated Credit Agreement (the “Amendment”), which amended the Credit Agreement to, among other things, extend the maturity date under the Credit Agreement from March 27, 2023 to March 27, 2024. The Company has the option, subject to certain conditions, to exercise two one-year extensions of the maturity date.

Loans under the Credit Agreement bear interest by reference, at the Company’s election, to the LIBOR rate or base rate. The applicable margin on LIBOR rate loans varies from 1.00% to 2.00% and the applicable margin on base rate loans varies from 0.00% to 1.00%, in each case determined based upon the Company’s credit rating. 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 varies from 0.10% to 0.30% based on the Company’s credit rating.

No subsidiaries of the Company are currently required to be a guarantor under the Credit Agreement. However, if any subsidiary guarantees or incurs debt in excess of the Priority Debt Basket (as defined in the Credit Agreement), such subsidiary is required to become a guarantor under the Credit Agreement.

The Credit Agreement contains representations, warranties, affirmative and negative covenants and events of default and associated remedies that the Company believes are customary for agreements of this nature, including certain restrictions on the ability of the Company and each subsidiary of the Company to incur debt and grant liens. If the Company’s credit rating is below investment grade, the Company will become subject to a restricted payment covenant, which would require the Company to have a Pro Forma Debt Service Coverage Ratio (as defined in the Credit Agreement) greater than or equal to 1.50 to 1.00 immediately before and immediately after making any restricted payment. The Credit Agreement also requires that the Company’s total debt to capitalization ratio, expressed as a percentage, not exceed 50%. 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 end of the most recently ended fiscal quarter.

As of June 30, 2019, the Company had no amounts outstanding under the revolving credit facility. The Company had $81,000 in letters of credit outstanding under the revolving credit facility at June 30, 2019 and, as a result, had available borrowing capacity of approximately $600 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, 2019, the Company had $63.3 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. No subsidiaries of the Company currently guarantee payment under the Credit Agreement.

Series A & B 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. No subsidiaries of the Company are currently required to be a guarantor 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, 2019.

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.

2028 Senior Notes – On January 19, 2018, the Company completed its offering of $525 million aggregate principal amount of the Company’s 3.95% Senior Notes due 2028 (the “2028 Notes”). The net proceeds before offering expenses were approximately $521 million of which the Company used $239 million to repay amounts outstanding under its revolving credit facility.

The Company pays interest on the 2028 Notes on February 1 and August 1 of each year. The 2028 Notes will mature on February 1, 2028. The 2028 Notes bear interest at a rate of 3.95% per annum.

The 2028 Notes are senior unsecured obligations of the Company, which rank equally with all of the Company’s other existing and future senior unsecured debt and will rank senior in right of payment to all of the Company’s other future subordinated debt. The 2028 Notes will be effectively subordinated to any of the Company’s future secured debt to the extent of the value of the assets securing such debt. In addition, the 2028 Notes will be structurally subordinated to the liabilities (including trade payables) of the Company’s subsidiaries that do not guarantee the 2028 Notes. No subsidiaries of the Company are currently required to be a guarantor under the 2028 Notes. If subsidiaries of the Company guarantee the 2028 Notes in the future, such guarantees (the “Guarantees”) will rank equally in right of payment with all of the guarantors’ future unsecured senior debt and senior in right of payment to all of the guarantors’ future subordinated debt. The Guarantees will be effectively subordinated to any of the guarantors’ future secured debt to the extent of the value of the assets securing such debt.

The Company, at its option, may redeem the Notes in whole or in part, at any time or from time to time at a redemption price equal to 100% of the principal amount of such 2028 Notes to be redeemed, plus accrued and unpaid interest, if any, on those 2028 Notes to the redemption date, plus a make-whole premium. Additionally, commencing on November 1, 2027, the Company, at its option, may redeem the 2028 Notes in whole or in part, at a redemption price equal to 100% of the principal amount of the 2028 Notes to be redeemed, plus accrued and unpaid interest, if any, on those 2028 Notes to the redemption date.

The indenture pursuant to which the 2028 Notes were issued includes covenants that, among other things, limit the Company and its subsidiaries’ ability to incur certain liens, engage in sale and lease-back transactions or consolidate, merge, or transfer all or substantially all of their assets. These covenants are subject to important qualifications and limitations set forth in the indenture.

Upon the occurrence of a change of control, as defined in the indenture, each holder of the 2028 Notes may require the Company to purchase all or a portion of such holder’s 2028 Notes at a price equal to 101% of their principal amount, plus accrued and unpaid interest, if any, to, but excluding, the repurchase date.

The indenture also provides for events of default which, if any of them occurs, would permit or require the principal, premium, if any, and accrued interest, if any, on the 2028 Notes to become or to be declared due and payable.

Debt issuance costs – 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 $336,000 and $354,000 for the three months ended June 30, 2019 and 2018, respectively and $0.7 million and $1.3 million for the six months ended June 30, 2019 and 2018, respectively. Amortization of debt issuance costs for the six months ended June 30, 2018 includes $317,000 of debt issuance costs related to commitments by lenders under the Company’s previous credit agreement who did not participate in the 2018 Credit Agreement.

Presented below is a schedule of the principal repayment requirements of long-term debt as of June 30, 2019 (in thousands):

Year ending December 31,
2019	$	—
2020		300,000
2021		—
2022		300,000
2023		—
Thereafter		525,000
Total	$	1,125,000

10. Commitments and Contingencies

As of June 30, 2019, the Company maintained letters of credit in the aggregate amount of $63.4 million primarily 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, 2019, no amounts had been drawn under the letters of credit.

As of June 30, 2019, the Company had commitments to purchase major equipment and make investments totaling approximately $72.8 million for its drilling, pressure pumping, directional drilling and oilfield rentals businesses.

The Company’s pressure pumping business has entered into agreements to purchase minimum quantities of proppants and chemicals from certain vendors. The agreements expire in years 2019 through 2023. As of June 30, 2019, the remaining obligation under these agreements was approximately $42.2 million, of which approximately $14.9 million relates to purchases required during the remainder of 2019. In the event the required minimum quantities are not purchased during any contract year, the Company could be required to make a liquidated damages payment to the respective vendor for any shortfall. In 2017, the Company entered into a capacity reservation agreement that required a cash deposit to increase the Company’s access to finer grades of sand for its pressure pumping business. As market prices for sand have substantially decreased since 2017, the Company has purchased lower cost sand outside of this capacity reservation contract and recorded a charge of $12.7 million in the quarter ended June 30, 2019 to revalue the deposit to its expected realizable value.

On January 22, 2018, an accident at a drilling site in Pittsburg County, Oklahoma resulted in the losses of life of five people, including three of the Company’s employees. Lawsuits have been filed in the District Court for Pittsburg County, Oklahoma in connection with the five individuals who lost their lives and one of the Company’s employees who was injured in the accident. The lawsuits have been consolidated for discovery purposes under Cause No. CJ-2018-60 (the “Litigation”). The Company has finalized settlement agreements with each of the plaintiffs who brought wrongful death lawsuits, and the Company has been dismissed from those lawsuits. The remaining lawsuit by the Company’s surviving employee alleges various causes of action against the Company including negligence, negligence per se, gross negligence and intentional conduct, and the plaintiff seeks an unspecified amount of damages, including punitive or exemplary damages, costs, interest, and other relief. The Company disputes the plaintiff’s allegations and intends to continue to defend itself vigorously. Based on the information the Company has available as of the date of this Report, the Company believes that it has adequate insurance to cover the Litigation. However, if this accident is not fully covered by insurance or an enforceable and recoverable indemnity from a third party, it could have a material adverse effect on the Company’s business, financial condition, cash flows and results of operations.

The Company is party to various other 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, cash flows or results of operations.

11. Stockholders’ Equity

Cash Dividends — The Company paid cash dividends during the six months ended June 30, 2019 and 2018 as follows:

2019:	Per Share		Total
			(in thousands)
Paid on March 21, 2019	$	0.04	$	8,499
Paid on June 20, 2019		0.04		8,344
Total cash dividends	$	0.08	$	16,843

2018:	Per Share		Total
			(in thousands)
Paid on March 22, 2018	$	0.02	$	4,443
Paid on June 21, 2018		0.04		8,832
Total cash dividends	$	0.06	$	13,275

On July 24, 2019, the Company’s Board of Directors approved a cash dividend on its common stock in the amount of $0.04 per share to be paid on September 19, 2019 to holders of record as of September 5, 2019. 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 authorized purchases of up to $200 million of the Company’s common stock in open market or privately negotiated transactions. On July 25, 2018, the Company’s Board of Directors approved an increase of the authorization under the stock buyback program to allow for $250 million of future share repurchases. On February 6, 2019, the Company’s Board of Directors approved another increase of the authorization under the stock buyback program to allow for $250 million of future share repurchases. All purchases executed to date have been through open market transactions. Purchases under the program are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Purchases may be made at any time without prior notice. There is no expiration date associated with the buyback program. As of June 30, 2019, the Company had remaining authorization to purchase approximately $100 million of the Company’s outstanding common stock under the stock buyback program. Shares of stock purchased under the buyback program are held as treasury shares. On July 24, 2019, the Company’s Board of Directors approved another increase of the authorization under the stock buyback program to allow for $250 million of future share repurchases.

The Company acquired shares of stock from employees during the first two quarters of 2019 that are accounted for as treasury stock. Certain of these shares were acquired to satisfy the exercise price and employees’ tax withholding obligation upon the exercise of stock options. The remainder of these shares was acquired to satisfy payroll withholding obligations upon the settlement of performance unit awards and the vesting of restricted stock and restricted stock units. These shares were acquired at fair market value. These acquisitions were made pursuant to the terms of the Patterson-UTI Energy, Inc. Amended and Restated 2014 Long-Term Incentive Plan (the “2014 Plan”) and not pursuant to the stock buyback program.

Treasury stock acquisitions during the six months ended June 30, 2019 were as follows (dollars in thousands):

	Shares		Cost
Treasury shares at beginning of period		53,701,096	$	1,080,448
Purchases pursuant to stock buyback program		11,745,128		150,110
Acquisitions pursuant to long-term incentive plan		912,338		12,890
Other		31,013		371
Treasury shares at end of period		66,389,575	$	1,243,819

The reconciliation of changes in stockholders’ equity for the periods ended June 30, 2019 and 2018, are presented as follows (in thousands):

	For the six months ended June 30, 2019

	Common Stock					Additional						Accumulated Other
	Number of					Paid-in			Retained			Comprehensive		Treasury
	Shares			Amount		Capital			Earnings			Income (Loss)		Stock			Total
Balance, December 31, 2018		267,316		$	2,673	$	2,827,154		$	1,753,557		$	2,487	$	(1,080,448	)	$	3,505,423
Net loss		—			—		—			(28,614	)		—		—			(28,614	)
Foreign currency translation adjustment		—			—		—			—			944		—			944
Vesting of restricted stock units		38			—		—			—			—		—			—
Forfeitures of restricted stock		(1	)		—		—			—			—		—			—
Stock-based compensation		—			—		9,338			—			—		—			9,338
Payment of cash dividends		—			—		—			(8,499	)		—		—			(8,499	)
Dividend equivalents		—			—		—			(110	)		—		—			(110	)
Purchase of treasury stock		—			—		—			—			—		(75,113	)		(75,113	)
Balance, March 31, 2019		267,353		$	2,673	$	2,836,492		$	1,716,334		$	3,431	$	(1,155,561	)	$	3,403,369
Net loss		—			—		—			(49,447	)		—		—			(49,447	)
Foreign currency translation adjustment		—			—		—			—			848		—			848
Exercise of stock options		700			7		9,212			—			—		—			9,219
Vesting of restricted stock units		739			8		(8	)		—			—		—			—
Forfeitures of restricted stock		(1	)		—		—			—			—		—			—
Stock-based compensation		—			—		11,050			—			—		—			11,050
Payment of cash dividends		—			—		—			(8,344	)		—		—			(8,344	)
Dividend equivalents		—			—		—			(126	)		—		—			(126	)
Purchase of treasury stock		—			—		—			—			—		(88,258	)		(88,258	)
Balance, June 30, 2019		268,791		$	2,688	$	2,856,746		$	1,658,417		$	4,279	$	(1,243,819	)	$	3,278,311

	For the six months ended June 30, 2018

	Common Stock					Additional						Accumulated Other
	Number of					Paid-in			Retained			Comprehensive			Treasury
	Shares			Amount		Capital			Earnings			Income (Loss)			Stock			Total
Balance, December 31, 2017		266,259		$	2,662	$	2,785,823		$	2,105,897		$	6,822		$	(918,711	)	$	3,982,493
Net loss		—			—		—			(34,417	)		—			—			(34,417	)
Foreign currency translation adjustment		—			—		—			—			(1,984	)		—			(1,984	)
Exercise of stock options		40			1		484			—			—			—			485
Stock-based compensation		—			—		9,365			—			—			—			9,365
Payment of cash dividends		—			—		—			(4,443	)		—			—			(4,443	)
Dividend equivalents		—			—		—			(30	)		—			—			(30	)
Purchase of treasury stock		—			—		—			—			—			(16,928	)		(16,928	)
Balance, March 31, 2018		266,299		$	2,663	$	2,795,672		$	2,067,007		$	4,838		$	(935,639	)	$	3,934,541
Net loss		—			—		—			(10,713	)		—			—			(10,713	)
Foreign currency translation adjustment		—			—		—			—			(1,530	)		—			(1,530	)
Issuance of common stock		381			4		(4	)		—			—			—			—
Vesting of restricted stock units		10			—		—			—			—			—			—
Forfeitures of restricted stock		(2	)		—		—			—			—			—			—
Stock-based compensation		—			—		9,907			—			—			—			9,907
Payment of cash dividends		—			—		—			(8,832	)		—			—			(8,832	)
Dividend equivalents		—			—		—			(83	)		—			—			(83	)
Purchase of treasury stock		—			—		—			—			—			(42,951	)		(42,951	)
Balance, June 30, 2018		266,688		$	2,667	$	2,805,575		$	2,047,379		$	3,308		$	(978,590	)	$	3,880,339

12. 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 include 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.

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 during the six months ended June 30, 2019 or 2018.

Stock option activity from January 1, 2019 to June 30, 2019 follows:

				Weighted
				Average
	Underlying			Exercise Price
	Shares			Per Share
Outstanding at January 1, 2019		5,501,150		$	19.63
Exercised		(700,000	)	$	13.17
Expired		—		$	—
Outstanding at June 30, 2019		4,801,150		$	20.57
Exercisable at June 30, 2019		4,756,150		$	20.59

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, 2019 to June 30, 2019 follows:

				Weighted
				Average Grant
				Date Fair Value
	Shares			Per Share
Non-vested restricted stock outstanding at January 1, 2019		436,224		$	21.41
Vested		(274,177	)	$	21.33
Forfeited		(1,500	)	$	21.71
Non-vested restricted stock outstanding at June 30, 2019		160,547		$	21.55

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 and, in certain cases, performance conditions. Forfeitable dividend equivalents are accrued on certain restricted stock units that will be paid upon vesting. The Company uses the straight-line method to recognize periodic compensation cost over the vesting period.

Restricted stock unit activity from January 1, 2019 to June 30, 2019 follows:

						Weighted
						Average Grant
	Time			Performance		Date Fair Value
	Based			Based		Per Share
Non-vested restricted stock units outstanding at January 1, 2019		2,602,608			435,315	$	18.95
Granted		1,505,048			—	$	12.40
Vested		(591,679	)		—	$	19.39
Forfeited		(141,552	)		—	$	19.23
Non-vested restricted stock units outstanding at June 30, 2019		3,374,425			435,315	$	16.28

Performance Unit Awards. The Company has granted share-settled performance unit awards to certain employees (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 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. For the Performance Units granted in May 2017 and April 2018, 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. For the Performance Units granted in April 2019, the recipients will receive 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 55^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 target percentile, or the target and 75^th percentile, then the shares to be received by the recipients will be determined using linear interpolation for levels of achievement between these points.

In April 2019, 185,000 shares were issued to settle the 2016 Performance Units. For the Performance Units granted in May 2017 and April 2018, the payout is based on relative performance and does not have an absolute performance requirement. For the Performance Units granted in April 2019, the payout shall not exceed the target number of shares if the Company’s total shareholder return is negative or zero.

The total target number of shares with respect to the Performance Units for the awards granted in 2015-2019 is set forth below:

	2019		2018		2017		2016		2015
	Performance		Performance		Performance		Performance		Performance
	Unit Awards		Unit Awards		Unit Awards		Unit Awards		Unit Awards
Target number of shares		489,800		310,700		186,198		185,000		190,600

Because the performance units are share-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):

	2019		2018		2017		2016		2015
	Performance		Performance		Performance		Performance		Performance
	Unit Awards		Unit Awards		Unit Awards		Unit Awards		Unit Awards
Fair value at date of grant	$	9,958	$	8,004	$	5,780	$	3,854	$	4,052

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):

	2019		2018		2017		2016		2015
	Performance		Performance		Performance		Performance		Performance
	Unit Awards		Unit Awards		Unit Awards		Unit Awards		Unit Awards
Three months ended June 30, 2019	$	830	$	667	$	482	NA		NA
Three months ended June 30, 2018	NA		$	667	$	482	$	321	NA
Six months ended June 30, 2019	$	830	$	1,334	$	963	$	321	NA
Six months ended June 30, 2018	NA		$	667	$	963	$	642	$	338

13. Income Taxes

The Company’s effective income tax rate fluctuates from the U.S. statutory tax rate based on, among other factors, changes in pretax income in jurisdictions with varying statutory tax rates, the impact of U.S. state and local taxes, and other differences related to the recognition of income and expense between U.S. GAAP and tax accounting.

The Company’s effective income tax rate for the three months ended June 30, 2019 was 17.0%, compared with 43.9% for the three months ended June 30, 2018. The higher effective income tax rate for the three months ended June 30, 2018 was primarily attributable to changes in forecasted annual pretax income from the first quarter of 2018 to the second quarter of 2018. The Company also recorded tax expense related to the vesting of share-based compensation during the second quarter of 2019.

The Company’s effective income tax rate for the six months ended June 30, 2019 was 17.7%, compared with 15.2% for the six months ended June 30, 2018. The change in the effective income tax rate for the six months ended June 30, 2019 was primarily attributable to the impact of various non-deductible expenses for U.S. tax purposes when measured against annual forecasted pretax book income in the computation of the effective tax rate, as well as the impact of non-U.S. valuation allowances booked in 2018.

The Company continues to monitor income tax developments in the United States and other countries affecting the Company. In December 2017, the United States enacted U.S. Tax Reform, which materially impacted the consolidated financial statements by decreasing the U.S. corporate statutory tax rate and significantly affecting future periods. The Company expects several proposed U.S. Treasury regulations under U.S. Tax Reform that were issued during 2018 to be finalized during 2019, as well as additional regulations to be proposed and finalized during 2019. The Company will incorporate into its future financial statements the impacts, if any, of these regulations and additional authoritative guidance when finalized.

14. Earnings Per Share

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, performance units and restricted stock units. The dilutive effect of stock options, performance units 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, 2019 and 2018 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,
	2019			2018			2019			2018
BASIC EPS:
Net loss attributed to common stockholders	$	(49,447	)	$	(10,713	)	$	(78,061	)	$	(45,130	)
Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock		207,499			220,093			209,671			220,436
Basic net loss per common share	$	(0.24	)	$	(0.05	)	$	(0.37	)	$	(0.21	)
DILUTED EPS:
Net loss attributed to common stockholders	$	(49,447	)	$	(10,713	)	$	(78,061	)	$	(45,130	)
Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock		207,499			220,093			209,671			220,436
Add dilutive effect of potential common shares		—			—			—			—
Weighted average number of diluted common shares outstanding		207,499			220,093			209,671			220,436
Diluted net loss per common share	$	(0.24	)	$	(0.05	)	$	(0.37	)	$	(0.21	)
Potentially dilutive securities excluded as anti-dilutive		10,289			9,903			10,289			9,903

15. Business Segments

At June 30, 2019, the Company had three reportable business segments: (i) contract drilling of oil and natural gas wells, (ii) pressure pumping services and (iii) directional drilling 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,
	2019			2018			2019			2018
Revenues:
Contract drilling	$	348,494		$	350,340		$	721,237		$	678,493
Pressure pumping		251,008			425,303			498,609			832,087
Directional drilling		50,218			52,705			103,177			101,321
Other operations ⁽¹⁾		27,852			31,717			63,243			61,370
Elimination of intercompany revenues ⁽²⁾		(1,807	)		(5,647	)		(6,330	)		(9,689	)
Total revenues	$	675,765		$	854,418		$	1,379,936		$	1,663,582

Income (loss) before income taxes:
Contract drilling	$	16,494		$	(251	)	$	37,711		$	(17,354	)
Pressure pumping		(14,408	)		20,637			(33,176	)		46,026
Directional drilling		(5,290	)		(7,678	)		(10,957	)		(12,591	)
Other operations		(7,317	)		(4,777	)		(12,521	)		(8,866	)
Corporate		(24,939	)		(24,064	)		(48,636	)		(47,871	)
Other operating (expenses) income, net ⁽³⁾		(9,071	)		7,129			(335	)		9,550
Provision for bad debts		(3,594	)		—			(3,594	)		—
Interest income		1,756			2,360			2,788			3,783
Interest expense		(13,298	)		(12,667	)		(26,282	)		(26,292	)
Other		92			216			209			385
Loss before income taxes	$	(59,575	)	$	(19,095	)	$	(94,793	)	$	(53,230	)

Depreciation, depletion, amortization and impairment:
Contract drilling	$	128,402		$	130,938		$	258,719		$	261,855
Pressure pumping		56,185			57,862			116,320			114,384
Directional drilling		10,870			11,874			21,237			22,776
Other operations		11,457			9,829			23,245			19,143
Corporate		1,774			1,881			3,577			4,118
Total depreciation, depletion, amortization and impairment	$	208,688		$	212,384		$	423,098		$	422,276

Capital expenditures:
Contract drilling	$	47,664		$	121,095		$	123,389		$	196,342
Pressure pumping		38,802			56,195			70,202			81,118
Directional drilling		3,450			10,034			5,562			22,863
Other operations		6,230			7,311			14,003			16,707
Corporate		773			227			2,104			753
Total capital expenditures	$	96,919		$	194,862		$	215,260		$	317,783

	June 30, 2019		December 31, 2018
Identifiable assets:
Contract drilling	$	3,620,264	$	3,817,638
Pressure pumping		849,006		921,237
Directional drilling		221,556		239,341
Other operations		171,412		177,374
Corporate ⁽⁴⁾		329,545		314,276
Total assets	$	5,191,783	$	5,469,866

⁽¹⁾	Other operations includes the Company’s oilfield rentals business, pipe handling components and related technology business, the electrical controls and automation business, the oil and natural gas working interests and Middle East organizational activities.

⁽²⁾	Intercompany revenues consists of contract drilling and revenues from other operations for services provided to contract drilling, pressure pumping and within other operations.

⁽³⁾

Other operating income, net 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 certain legal-related expenses and settlements, net of insurance reimbursements.

⁽⁴⁾	Corporate assets primarily include cash on hand and certain property and equipment.

16. 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, 2019 and December 31, 2018 is set forth below (in thousands):

	June 30, 2019				December 31, 2018
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
3.95% Senior Notes	$	525,000	$	526,235	$	525,000	$	482,488
4.97% Series A Senior Notes		300,000		306,592		300,000		300,043
4.27% Series B Senior Notes		300,000		305,603		300,000		293,900
Total debt	$	1,125,000	$	1,138,430	$	1,125,000	$	1,076,431

The fair values of the 3.95% Senior Notes at June 30, 2019 and December 31, 2018 are based on discounted cash flows associated with the notes using the 4.15% market rate of interest at June 30, 2019 and the 5.07% market rate of interest at December 31, 2018. The fair value estimates of the 3.95% Senior Notes are considered Level 1 fair value estimates in the fair value hierarchy of fair value accounting. The fair values of the Series A Notes and Series B Notes at June 30, 2019 and December 31, 2018 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 4.13% at June 30, 2019 and 4.97% at December 31, 2018. For the Series B Notes, the current market rates used in measuring this fair value were 3.96% at June 30, 2019 and 4.92% at December 31, 2018. 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.

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. As used in this Report, “the Company,” “us,” “we,” our” and like terms refer collectively to Patterson-UTI Energy, Inc. and its consolidated subsidiaries. Patterson-UTI Energy, Inc. conducts its operations through its wholly-owned subsidiaries and has no employees or independent business operations. 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.

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 include, among others, risks and uncertainties relating to:

•

adverse oil and natural gas industry conditions;

•

global economic conditions;

•

volatility in customer spending and in oil and natural gas prices that could adversely affect demand for our services and their associated effect on rates;

•

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

•

competition and demand for our services;

•

strength and financial resources of competitors;

•

utilization, margins and planned capital expenditures;

•

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

•

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);

•

the ability to realize backlog;

•

specialization of methods, equipment and services and new technologies;

•

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

•

cybersecurity events;

•

the ability to retain management and field personnel;

•

loss of key customers;

•

synergies, costs and financial and operating impacts of acquisitions;

•

difficulty in building and deploying new equipment;

•

governmental regulation;

•

environmental risks and ability to satisfy future environmental costs;

•

legal proceedings and actions by governmental or other regulatory agencies;

•

technology-related disputes;

•

the ability to effectively identify and enter new markets;

•

weather;

•

operating costs;

•

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

•

ability to obtain insurance coverage on commercially reasonable terms;

•

financial flexibility;

•

interest rate volatility;

•

adverse credit and equity market conditions;

•

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

•

compliance with covenants under our debt agreements; 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, 2018 and may be contained in our future filings with the SEC. 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 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

Management Overview — We are a Houston, Texas-based oilfield services company that primarily owns and operates one of the largest fleets of land-based drilling rigs in the United States and a large fleet of pressure pumping equipment. Our contract drilling business operates in the continental United States and western Canada, and, from time to time, we pursue contract drilling opportunities outside of North America. Our pressure pumping business operates primarily in Texas and the Mid-Continent and Appalachian regions. We also provide a comprehensive suite of directional drilling services in most major producing onshore oil and gas basins in the United States, and we provide services that improve the statistical accuracy of horizontal wellbore placement. We have other operations through which we provide oilfield rental tools in select markets in the United States. We also manufacture and sell pipe handling components and related technology to drilling contractors, and provide electrical controls and automation to the energy, marine and mining industries, 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.

Oil prices have recovered from a 12-year low of $26.19 in February 2016 and reached a high of $77.41 in June 2018. Oil prices remain volatile, as the closing price of oil reached a fourth quarter 2018 high of $76.40 per barrel on October 3, 2018, before declining by 42% over the course of three months to reach a low of $44.48 per barrel in late December 2018. Oil prices averaged $59.88 per barrel in the second quarter of 2019 and closed at $55.87 per barrel on July 22, 2019. Despite oil prices in the mid-$50s to low-$60s, drilling and pressure pumping activity has recently declined, largely as a result of reduced customer spending.

Our average active rig count for the second quarter of 2019 was 158 rigs, which included 157 rigs operating in the United States and one rig operating in Canada. This was a decrease from our average active rig count for the first quarter of 2019 of 175, which included 174 rigs in the United States and one rig in Canada. We believe our customers are slowing drilling and completion activity to smooth their spending run rate and reduce the risk of budget exhaustion later in 2019. We expect our rig count to average 142 rigs during the third quarter. Based on term contracts (contracts with a duration of six months or more) currently in place, we expect an average of 92 rigs operating under term contracts during the third quarter of 2019 and an average of 58 rigs operating under term contracts during the twelve months ending June 30, 2020.

In pressure pumping, we ended the second quarter with 15 active spreads compared to 16 at the end of the first quarter. Across the pressure pumping industry, we expect completion activity will follow drilling activity lower in the third quarter. We expect to maintain 15 active spreads during the third quarter, but we expect lower utilization of the active spreads will negatively impact pressure pumping revenues and margin.

Our revenues, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas. During periods of improved oil and natural gas 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 oil and natural gas prices deteriorate, the demand for our services generally weakens, and we experience downward pressure on pricing for our services.

The North American oil and natural gas services industry is cyclical and, at times, experiences downturns in demand. During these periods, there has been substantially more oil and natural gas service equipment available than necessary to meet demand. As a result, oil and natural gas service contractors have had difficulty sustaining profit margins and, at times, have incurred losses during the downturn periods. Currently, there is an excess supply of drilling rigs, pressure pumping equipment and directional drilling equipment. We cannot predict either the future level of demand for our oil and natural gas services or future conditions in the oil and natural gas service businesses.

We are highly impacted by operational risks, competition, labor issues, weather, the availability of products used in our pressure pumping business, supplier delays 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 Item 1A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2018.

For the three and six months ended June 30, 2019 and 2018, our operating revenues consisted of the following (dollars in thousands):

	Three Months Ended June 30,								Six Months Ended June 30,
	2019				2018				2019				2018
Contract drilling	$	348,138	51.5	%	$	349,922	40.9	%	$	720,530	52.2	%	$	677,725	40.7	%
Pressure pumping		251,008	37.2	%		425,303	49.8	%		498,609	36.1	%		832,087	50.0	%
Directional drilling		50,218	7.4	%		52,705	6.2	%		103,177	7.5	%		101,321	6.1	%
Other operations		26,401	3.9	%		26,488	3.1	%		57,620	4.2	%		52,449	3.2	%
	$	675,765	100.0	%	$	854,418	100.0	%	$	1,379,936	100.0	%	$	1,663,582	100.0	%

Contract Drilling

Contract drilling revenues accounted for 51.5% of our consolidated second quarter 2019 revenues, and contract drilling revenues decreased 0.5% over the comparable 2018 period.

We have addressed our customers’ needs for drilling horizontal wells in shale and other unconventional resource plays by improving the capabilities of our drilling fleet during the last several years. The U.S. land rig industry refers to certain high specification rigs as “super-spec” rigs. We consider a super-spec rig to be a 1,500 horsepower, AC powered rig that has at least a 750,000 pound hookload, a 7,500 psi circulating system, and is pad capable. As of June 30, 2019, our rig fleet included 198 APEX^® rigs, of which 150 were considered super-spec rigs.

We maintain a backlog of commitments for contract drilling services under term contracts, which we define as contracts with a duration of six months or more. Our contract drilling backlog as of June 30, 2019 was approximately $720 million. Approximately 35% of the total June 30, 2019 backlog is reasonably expected to remain at June 30, 2020. 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 fees for other services such as for mobilization, other than initial 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. For contracts that contain variable dayrate pricing, our backlog calculation uses the dayrate in effect for periods where the dayrate is fixed, and, for periods that remain subject to variable pricing, uses the commodity price in effect at June 30, 2019. 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 that 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.

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,

•

development of new technologies that enhance drilling efficiency, and

•

construction of new technology drilling rigs.

Pressure Pumping

Pressure pumping revenues accounted for 37.2% of our consolidated second quarter 2019 revenues and decreased 41.0% from the comparable 2018 period. As of June 30, 2019, we had approximately 1.6 million horsepower in our pressure pumping fleet. The pressure pumping market showed signs of oversupply in the second half of 2018 and was oversupplied in the first six months of 2019. In response to oversupplied market conditions, we reduced the number of active pressure pumping spreads to 15 early in the second quarter of 2019.

Directional Drilling

Directional drilling revenues accounted for 7.4% of our consolidated second quarter 2019 revenues and decreased 4.7% from the comparable 2018 period. We provide a comprehensive suite of directional drilling services in most major producing onshore oil and gas basins in the United States. Our directional drilling services include directional drilling, downhole performance motors, measurement-while-drilling, and wireline steering tools, and we provide services that improve the statistical accuracy of horizontal wellbore placement.

Other Operations

Other operations revenues accounted for 3.9% of our consolidated second quarter 2019 revenues and decreased 0.3% from the comparable 2018 period. Our oilfield rentals business, with a fleet of premium oilfield rental tools, provides the largest revenue contribution to our other operations and provides specialized services for land-based oil and natural gas drilling, completion and workover activities. Other operations also includes the results of our electrical controls and automation business, the results of our pipe handling components and related technology business, and the results of our ownership, as a non-operating working interest owner, in oil and natural gas assets that are primarily located in Texas and New Mexico.

For the three and six months ended June 30, 2019 and 2018, our operating loss consisted of the following (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Contract drilling	$	16,494		$	(251	)	$	37,711		$	(17,354	)
Pressure pumping		(14,408	)		20,637			(33,176	)		46,026
Directional drilling		(5,290	)		(7,678	)		(10,957	)		(12,591	)
Other operations		(7,317	)		(4,777	)		(12,521	)		(8,866	)
Corporate		(37,604	)		(16,935	)		(52,565	)		(38,321	)
	$	(48,125	)	$	(9,004	)	$	(71,508	)	$	(31,106	)

Additional discussion of our operating revenues and operating loss follows in the “Results of Operations” section.

Our consolidated net loss for the second quarter of 2019 was $49.4 million compared to a net loss of $10.7 million for the second quarter of 2018.

Results of Operations

The following tables summarize results of operations by business segment for the three months ended June 30, 2019 and 2018:

Contract Drilling	2019		2018			% Change
	(dollars in thousands)
Revenues	$	348,138	$	349,922			(0.5	)%
Direct operating costs		201,792		217,674			(7.3	)%
Margin ⁽¹⁾		146,346		132,248			10.7	%
Selling, general and administrative		1,450		1,561			(7.1	)%
Depreciation, amortization and impairment		128,402		130,938			(1.9	)%
Operating income (loss)	$	16,494	$	(251	)	NA
Operating days ⁽²⁾		14,385		15,998			(10.1	)%
Average revenue per operating day	$	24.20	$	21.87			10.6	%
Average direct operating costs per operating day	$	14.03	$	13.61			3.1	%
Average margin per operating day ⁽¹⁾	$	10.17	$	8.27			23.1	%
Average rigs operating		158		176			(10.1	)%
Capital expenditures	$	47,664	$	121,095			(60.6	)%

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

⁽²⁾	A rig is considered to be operating if it is earning revenue pursuant to a contract on a given day.

Generally, the revenues in our contract drilling segment are most impacted by two primary factors: our average number of rigs operating and our average revenue per operating day. During the second quarter of 2019, our average number of rigs operating was 158, compared to 176 in the second quarter of 2018. Our average revenue per operating day is largely dependent on the pricing terms of our rig contracts.

Revenues decreased slightly due to a decrease in operating days. Average revenue per operating day increased compared to the second quarter of 2018. This increase was supported by our upgrades of additional rigs to super-spec capability.

Capital expenditures decreased from the comparable 2018 period primarily due to upgrading rigs to super-spec capability in 2018.

Pressure Pumping	2019			2018			% Change
	(dollars in thousands)
Revenues	$	251,008		$	425,303			(41.0	)%
Direct operating costs		206,137			342,885			(39.9	)%
Margin ⁽¹⁾		44,871			82,418			(45.6	)%
Selling, general and administrative		3,094			3,919			(21.1	)%
Depreciation, amortization and impairment		56,185			57,862			(2.9	)%
Operating income (loss)	$	(14,408	)	$	20,637		NA
Fracturing jobs		122			217			(43.8	)%
Other jobs		193			264			(26.9	)%
Total jobs		315			481			(34.5	)%
Average revenue per fracturing job	$	2,028.33		$	1,932.62			5.0	%
Average revenue per other job	$	18.40		$	22.44			(18.0	)%
Average revenue per total job	$	796.85		$	884.21			(9.9	)%
Average direct operating costs per total job	$	654.40		$	712.86			(8.2	)%
Average margin per total job ⁽¹⁾	$	142.45		$	171.35			(16.9	)%
Margin as a percentage of revenues ⁽¹⁾		17.9	%		19.4	%		(7.7	)%
Capital expenditures	$	38,802		$	56,195			(31.0	)%

⁽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.

Generally, the revenues in our pressure pumping segment are most impacted by our number of fracturing jobs and the size (including whether or not we provide proppant and other materials) of those jobs, which is reflected in our average revenue per fracturing job. Direct operating costs are also most impacted by these same factors. We completed 122 fracturing jobs during the second quarter of 2019, compared to 217 fracturing jobs in the second quarter of 2018. Our average revenue per fracturing job was $2.028 million in the second quarter of 2019, compared to $1.933 million in the second quarter of 2018.

Selling, general and administrative expenses decreased primarily as a result of cost reduction efforts. The decrease in capital expenditures was primarily due to higher maintenance capital expenditures in the second quarter of 2018 when activity levels were higher.

Directional Drilling	2019			2018			% Change
	(dollars in thousands)
Revenues	$	50,218		$	52,705			(4.7	)%
Direct operating costs		42,102			43,685			(3.6	)%
Margin ⁽¹⁾		8,116			9,020			(10.0	)%
Selling, general and administrative		2,536			4,824			(47.4	)%
Depreciation and amortization		10,870			11,874			(8.5	)%
Operating loss	$	(5,290	)	$	(7,678	)		(31.1	)%
Capital expenditures	$	3,450		$	10,034			(65.6	)%

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

Directional drilling revenue decreased by $2.5 million from the second quarter of 2018 due primarily to decreased job activity, partially offset by increased revenue from Superior QC, LLC (“Superior QC”), which was acquired in the first quarter of 2018. Directional drilling direct operating costs decreased by $1.6 million from the second quarter of 2018 primarily due to cost reduction efforts.

Selling, general and administrative expense decreased from the second quarter of 2018 primarily as a result of cost reduction efforts. The decrease in capital expenditures was primarily due to higher capital expenditures in the second quarter of 2018 in response to market demand and equipment upgrades.

Other Operations	2019			2018			% Change
	(dollars in thousands)
Revenues	$	26,401		$	26,488			(0.3	)%
Direct operating costs		17,612			17,513			0.6	%
Margin ⁽¹⁾		8,789			8,975			(2.1	)%
Selling, general and administrative		4,649			3,923			18.5	%
Depreciation, depletion, amortization and impairment		11,457			9,829			16.6	%
Operating loss	$	(7,317	)	$	(4,777	)		53.2	%
Capital expenditures	$	6,230		$	7,311			(14.8	)%

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

Depreciation, depletion, amortization and impairment expense in 2019 includes approximately $1.1 million of oil and natural gas property impairments, whereas no oil and natural gas property impairments were recorded in 2018.

Corporate	2019			2018			% Change
	(dollars in thousands)
Selling, general and administrative	$	23,165		$	21,436			8.1	%
Merger and integration expenses	$	—		$	747			(100.0	)%
Depreciation	$	1,774		$	1,881			(5.7	)%
Other operating expenses (income), net
Net gain on asset disposals	$	(3,971	)	$	(7,062	)		(43.8	)%
Legal-related expenses and settlements, net of insurance reimbursements		—			3,441			(100.0	)%
Research and development		371			—			100	%
Other		12,671			(3,508	)	NA
Other operating expenses (income), net	$	9,071		$	(7,129	)	NA
Provision for bad debts	$	3,594		$	—			100.0	%
Interest income	$	1,756		$	2,360			(25.6	)%
Interest expense	$	13,298		$	12,667			5.0	%
Other income	$	92		$	216			(57.4	)%
Capital expenditures	$	773		$	227			240.5	%

Selling, general and administrative expense increased in 2019 primarily due to an increase in compensation related expenses. Merger and integration expenses incurred in 2018 are related to the Seventy Seven Energy Inc. (“SSE”) merger. Other operating expenses (income), net includes net gains associated with the disposal of assets. Accordingly, the related gains or losses have been excluded from the results of specific segments. The majority of the net gain on asset disposals during 2019 reflect gains on disposal of drilling equipment. Legal-related expenses and settlements in 2018 includes insurance deductibles and investigation costs related to an accident at a drilling site in January 2018.

Other operating expenses (income), net includes a $12.7 million charge recorded in the quarter ended June 30, 2019 related to a 2017 capacity reservation agreement that required a cash deposit to increase our access to finer grades of sand for our pressure pumping business. As market prices for sand have substantially decreased since 2017, we have purchased lower cost sand outside of this capacity reservation contract and have revalued the deposit at its expected realizable value. Other operating expenses (income), net also includes a $3.5 million gain recorded in the quarter ended June 30, 2018 related to the collection of a note receivable that had been recorded at a discount. A provision for bad debts was recognized in 2019 with respect to accounts receivable balances that are estimated to be uncollectible.

The following tables summarize results of operations by business segment for the six months ended June 30, 2019 and 2018:

Contract Drilling	2019		2018			% Change
	(dollars in thousands)
Revenues	$	720,530	$	677,725			6.3	%
Direct operating costs		420,994		430,257			(2.2	)%
Margin ⁽¹⁾		299,536		247,468			21.0	%
Selling, general and administrative		3,106		2,967			4.7	%
Depreciation, amortization and impairment		258,719		261,855			(1.2	)%
Operating income (loss)	$	37,711	$	(17,354	)	NA
Operating days		30,172		31,216			(3.3	)%
Average revenue per operating day	$	23.88	$	21.71			10.0	%
Average direct operating costs per operating day	$	13.95	$	13.78			1.2	%
Average margin per operating day ⁽¹⁾	$	9.93	$	7.93			25.2	%
Average rigs operating		167		172			(2.9	)%
Capital expenditures	$	123,389	$	196,342			(37.2	)%

⁽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 operating day is defined as margin divided by operating days.

During the first six months of 2019, our average number of rigs operating was 167, compared to 172 in the same period of 2018. Our average rig revenue per operating day was $23,880 in the first half of 2019, compared to $21,710 in the first half of 2018. Our average revenue per operating day is largely dependent on the pricing terms of our rig contracts.

Revenues increased primarily due to higher average revenue per operating day supported by higher day rates on term contracts.

Capital expenditures decreased over the comparable 2018 period due to upgrading rigs to super-spec capability in 2018.

Pressure Pumping	2019			2018			% Change
	(dollars in thousands)
Revenues	$	498,609		$	832,087			(40.1	)%
Direct operating costs		408,885			663,855			(38.4	)%
Margin ⁽¹⁾		89,724			168,232			(46.7	)%
Selling, general and administrative		6,580			7,822			(15.9	)%
Depreciation, amortization and impairment		116,320			114,384			1.7	%
Operating income (loss)	$	(33,176	)	$	46,026		NA
Fracturing jobs		286			421			(32.1	)%
Other jobs		456			544			(16.2	)%
Total jobs		742			965			(23.1	)%
Average revenue per fracturing job	$	1,711.92		$	1,948.88			(12.2	)%
Average revenue per other job	$	19.73		$	21.34			(7.5	)%
Average revenue per total job	$	671.98		$	862.27			(22.1	)%
Average direct operating costs per total job	$	551.06		$	687.93			(19.9	)%
Average margin per total job ⁽¹⁾	$	120.92		$	174.33			(30.6	)%
Margin as a percentage of revenues ⁽¹⁾		18.0	%		20.2	%		(10.9	)%
Capital expenditures and acquisitions	$	70,202		$	81,118			(13.5	)%

⁽¹⁾

We completed 286 fracturing jobs during the first six months of 2019, compared to 421 fracturing jobs in the same period of 2018. Our average revenue per fracturing job was $1.712 million in the first half of 2019, compared to $1.949 million in the first half of 2018.

Revenues and direct operating costs during the six months ended June 30, 2019 decreased primarily due to a decline in the number of fracturing jobs, as compared to the six months ended June 30, 2018. Average revenue and direct operating costs per job were impacted by lower demand, more customers self-sourcing products and decreases in product prices.

The decrease in capital expenditures was primarily due to higher maintenance capital expenditures in the second quarter of 2018 when activity levels were higher.

Directional Drilling	2019			2018			% Change
	(dollars in thousands)
Revenues	$	103,177		$	101,321			1.8	%
Direct operating costs		87,704			81,374			7.8	%
Margin ⁽¹⁾		15,473			19,947			(22.4	)%
Selling, general and administrative		5,193			9,762			(46.8	)%
Depreciation and amortization		21,237			22,776			(6.8	)%
Operating loss	$	(10,957	)	$	(12,591	)		(13.0	)%
Capital expenditures	$	5,562		$	22,863			(75.7	)%

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

Directional drilling direct operating costs increased by $6.3 million from the six months ended June 30, 2018 due primarily to increased repairs and maintenance expense and labor costs.

Selling, general and administrative expense decreased in the six months ended June 30, 2019 primarily as a result of cost reduction efforts. The decrease in capital expenditures was primarily due to higher capital expenditures in 2018 in response to market demand and equipment upgrades.

Other Operations	2019			2018			% Change
	(dollars in thousands)
Revenues	$	57,620		$	52,449			9.9	%
Direct operating costs		39,385			35,258			11.7	%
Margin ⁽¹⁾		18,235			17,191			6.1	%
Selling, general and administrative		7,511			6,914			8.6	%
Depreciation, depletion, amortization and impairment		23,245			19,143			21.4	%
Operating loss	$	(12,521	)	$	(8,866	)		41.2	%
Capital expenditures	$	14,003		$	16,707			(16.2	)%

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

Revenues, direct operating costs, selling, general and administrative expense and depreciation, depletion and impairment expense from other operations increased primarily as a result of an increase in the volume of services provided and the acquisition of Current Power Solutions, Inc. in the fourth quarter of 2018. Capital expenditures decreased in 2019 primarily due to a decrease in oil and natural gas capital expenditures.

Corporate	2019			2018			% Change
	(dollars in thousands)
Selling, general and administrative	$	45,059		$	41,015			9.9	%
Merger and integration expenses	$	—		$	2,738			(100.0	)%
Depreciation	$	3,577		$	4,118			(13.1	)%
Other operating expenses (income), net
Net gain on asset disposals	$	(10,516	)	$	(17,472	)		(39.8	)%
Legal-related expenses and settlements, net of insurance reimbursements		(3,471	)		9,321		NA
Research and development		1,726			2,109			(18.2	)%
Other		12,596			(3,508	)	NA
Other operating expenses (income), net	$	335		$	(9,550	)	NA
Provision for bad debts	$	3,594		$	—			100.0	%
Interest income	$	2,788		$	3,783			(26.3	)%
Interest expense	$	26,282		$	26,292			(0.0	)%
Other income	$	209		$	385			(45.7	)%
Capital expenditures	$	2,104		$	753			179.4	%

Selling, general and administrative expense increased in the six months ended June 30, 2019 due to an increase in compensation related expenses. Merger and integration expenses incurred in 2018 are related to the SSE merger, MS Directional, LLC (f/k/a Multi-Shot, LLC) acquisition and Superior QC acquisition. Other operating expenses (income), net includes net gains associated with the disposal of assets. Accordingly, the related gains or losses have been excluded from the results of specific segments. The majority of the net gain on asset disposals during 2019 reflect gains on disposal of drilling equipment. Legal-related expenses and settlements in 2018 includes insurance deductibles and investigation costs related to an accident at a drilling site in January 2018. Legal-related expenses and settlements in 2019 includes proceeds from insurance claims.

Other operating expenses (income), net includes a $12.7 million charge recorded in the quarter ended June 30, 2019 related to a 2017 capacity reservation agreement that required a cash deposit to increase our access to finer grades of sand for our pressure pumping business. As market prices for sand have substantially decreased since 2017, we have purchased lower cost sand outside of this capacity reservation contract and have revalued the deposit at its expected realizable value. Other operating expenses (income), net includes a $3.5 million gain recorded in the quarter ended June 30, 2018 related to the collection of a note receivable that had been recorded at a discount. A provision for bad debts was recognized in 2019 with respect to accounts receivable balances that are estimated to be uncollectible.

Income Taxes

Our effective income tax rate fluctuates from the U.S. statutory tax rate based on, among other factors, changes in pretax income in jurisdictions with varying statutory tax rates, the impact of U.S. state and local taxes, and other differences related to the recognition of income and expense between U.S. GAAP and tax accounting.

Our effective income tax rate for the three months ended June 30, 2019 was 17.0%, compared with 43.9% for the three months ended June 30, 2018. The higher effective income tax rate for the three months ended June 30, 2018 was primarily attributable to changes in forecasted annual pretax income from the first quarter of 2018 to the second quarter of 2018. We also recorded tax expense related to the vesting of share-based compensation during the second quarter of 2019.

Our effective income tax rate for the six months ended June 30, 2019 was 17.7%, compared with 15.2% for the six months ended June 30, 2018. The change in the effective income tax rate for the six months ended June 30, 2019 was primarily attributable to the impact of various non-deductible expenses for U.S. tax purposes when measured against annual forecasted pretax book income in the computation of the effective tax rate, as well as the impact of non-U.S. valuation allowances booked in 2018.

We continue to monitor income tax developments in the United States and other countries affecting us. In December 2017, the United States enacted U.S. Tax Reform, which materially impacted the consolidated financial statements by decreasing the U.S. corporate statutory tax rate and significantly affecting future periods. We expect several proposed U.S. Treasury regulations under U.S. Tax Reform that were issued during 2018 to be finalized during 2019, as well as additional regulations to be proposed and finalized during 2019. We will incorporate into our future financial statements the impacts, if any, of these regulations and additional authoritative guidance when finalized.

Liquidity and Capital Resources

Our liquidity as of June 30, 2019 included approximately $428 million in working capital, including $256 million of cash and cash equivalents, and approximately $600 million available under our revolving credit facility.

On January 19, 2018, we completed an offering of $525 million aggregate principal amount of our 2028 Notes. We used $239 million of the net proceeds from the offering to repay amounts outstanding under our revolving credit facility. As described below, on March 27, 2018, we entered into an amended and restated credit agreement, which is a committed senior unsecured revolving credit facility that permits aggregate borrowings of up to $600 million, including a letter of credit facility that, at any time outstanding, is limited to $150 million, and a swing line facility that, at any time outstanding, is limited to $20 million.

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 and pay cash dividends for at least the next 12 months. Given our current public market equity valuation, our cash balance and expected future cash flow generation, we will likely allocate additional capital to both share repurchases and debt repayment in the back half of 2019.

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

During the six months ended June 30, 2019, our sources of cash flow included:

•

$365 million from operating activities, and

•

$31.5 million in proceeds from the disposal of property and equipment and insurance proceeds.

During the six months ended June 30, 2019, we used $16.8 million to pay dividends on our common stock, $154 million for the repurchases of our common stock and $215 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, directional drilling, oilfield rentals 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, 2019 as follows:

	Per Share		Total
			(in thousands)
Paid on March 21, 2019	$	0.04	$	8,499
Paid on June 20, 2019		0.04		8,344
	$	0.08	$	16,843

On July 24, 2019, our Board of Directors approved a cash dividend on our common stock in the amount of $0.04 per share to be paid on September 19, 2019 to holders of record as of September 5, 2019. 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 authorized purchases of up to $200 million of our common stock in open market or privately negotiated transactions. On July 25, 2018, our Board of Directors approved an increase of the authorization under the stock buyback program to allow for $250 million of future share repurchases. On February 6, 2019, our Board of Directors approved another increase of the authorization under the stock buyback program to allow for $250 million of future share repurchases. All purchases executed to date have been through open market transactions. Purchases under the program are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Purchases may be made at any time without prior notice. Shares of stock purchased under the buyback program are held as treasury shares. There is no expiration date associated with the buyback program. As of June 30, 2019, we had remaining authorization to purchase approximately $100 million of our outstanding common stock under the stock buyback program. On July 24, 2019, our Board of Directors approved another increase of the authorization under the stock buyback program to allow for $250 million of future share repurchases.

Treasury stock acquisitions during the six months ended June 30, 2019 were as follows (dollars in thousands):

	Shares		Cost
Treasury shares at beginning of period		53,701,096	$	1,080,448
Purchases pursuant to stock buyback program		11,745,128		150,110
Acquisitions pursuant to long-term incentive plan ⁽¹⁾		912,338		12,890
Other		31,013		371
Treasury shares at end of period		66,389,575	$	1,243,819

⁽¹⁾

We withheld 912,338 shares during the first two quarters of 2019 with respect to the exercise price and employees’ tax withholding obligations upon the exercise of stock options and the employees’ tax withholding obligations upon the settlement of performance unit awards and the vesting of restricted stock and restricted stock units. These shares were acquired at fair market value. These acquisitions were made pursuant to the terms of the Patterson-UTI Energy, Inc. Amended and Restated 2014 Long-Term Incentive Plan and not pursuant to the stock buyback program.

Credit Agreement — On March 27, 2018, we entered into an amended and restated credit agreement (the “Credit Agreement”) among us, as borrower, Wells Fargo Bank, National Association, as administrative agent, letter of credit issuer, swing line lender and lender, each of the other lenders and letter of credit issuers party thereto, The Bank of Nova Scotia and U.S. Bank National Association, as Co-Syndication Agents, Royal Bank of Canada, as Documentation Agent and Wells Fargo Securities, LLC, The Bank of Nova Scotia and U.S. Bank National Association, as Co-Lead Arrangers and Joint Book Runners.

The Credit Agreement is a committed senior unsecured revolving credit facility that permits aggregate borrowings of up to $600 million, including a letter of credit facility that, at any time outstanding, is limited to $150 million and a swing line facility that, at any time outstanding, is limited to $20 million. Subject to customary conditions, we may request that the lenders’ aggregate commitments be increased by up to $300 million, not to exceed total commitments of $900 million. The original maturity date under the Credit Agreement was March 27, 2023. On March 26, 2019, we entered into Amendment No. 1 to Amended and Restated Credit Agreement (the “Amendment”), which amended the Credit Agreement to, among other things, extend the maturity date under the Credit Agreement from March 27, 2023 to March 27, 2024. We have the option, subject to certain conditions, to exercise two one-year extensions of the maturity date.

Loans under the Credit Agreement bear interest by reference, at our election, to the LIBOR rate or base rate. The applicable margin on LIBOR rate loans varies from 1.00% to 2.00% and the applicable margin on base rate loans varies from 0.00% to 1.00%, in each case determined based upon our credit rating. 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 varies from 0.10% to 0.30% based on our credit rating.

None of our subsidiaries are currently required to be a guarantor under the Credit Agreement. However, if any subsidiary guarantees or incurs debt in excess of the Priority Debt Basket (as defined in the Credit Agreement), such subsidiary is required to become a guarantor under the Credit Agreement.

The Credit Agreement contains representations, warranties, affirmative and negative covenants and events of default and associated remedies that we believe are customary for agreements of this nature, including certain restrictions on our ability and each of our subsidiaries to incur debt and grant liens. If our credit rating is below investment grade, we will become subject to a restricted payment covenant, which would require us to have a Pro Forma Debt Service Coverage Ratio (as defined in the Credit Agreement) greater than or equal to 1.50 to 1.00 immediately before and immediately after making any restricted payment. The Credit Agreement also requires that our total debt to capitalization ratio, expressed as a percentage, not exceed 50%. 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 end of the most recently ended fiscal quarter.

As of June 30, 2019, we had no amounts outstanding under our revolving credit facility. We had $81,000 in letters of credit outstanding under our revolving credit facility at June 30, 2019 and, as a result, had available borrowing capacity of approximately $600 million at that date.

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, 2019, we had $63.3 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. None of our subsidiaries are currently required to guarantee payment under the Credit Agreement.

Series A & B 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. None of our subsidiaries are currently required to be a guarantor 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 covenants at June 30, 2019. 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.

2028 Senior Notes — On January 19, 2018, we completed an offering of $525 million aggregate principal amount of our 2028 Notes. The net proceeds before offering expenses were approximately $521 million, of which we used $239 million to repay amounts outstanding under our revolving credit facility.

We pay interest on the 2028 Notes on February 1 and August 1 of each year. The 2028 Notes will mature on February 1, 2028. The 2028 Notes bear interest at a rate of 3.95% per annum.

The 2028 Notes are senior unsecured obligations, which rank equally with all of our other existing and future senior unsecured debt and will rank senior in right of payment to all of our other future subordinated debt. The 2028 Notes will be effectively subordinated to any of our future secured debt to the extent of the value of the assets securing such debt. In addition, the 2028 Notes will be structurally subordinated to the liabilities (including trade payables) of our subsidiaries that do not guarantee the 2028 Notes. None of our subsidiaries are currently required to be a guarantor under the 2028 Notes. If our subsidiaries guarantee the 2028 Notes in the future, such guarantees (the “Guarantees”) will rank equally in right of payment with all of the guarantors’ future unsecured senior debt and senior in right of payment to all of the guarantors’ future subordinated debt. The Guarantees will be effectively subordinated to any of the guarantors’ future secured debt to the extent of the value of the assets securing such debt.

We, at our option, may redeem the Notes in whole or in part, at any time or from time to time at a redemption price equal to 100% of the principal amount of such 2028 Notes to be redeemed, plus accrued and unpaid interest, if any, on those 2028 Notes to the redemption date, plus a make-whole premium. Additionally, commencing on November 1, 2027, we, at our option, may redeem the 2028 Notes in whole or in part, at a redemption price equal to 100% of the principal amount of the 2028 Notes to be redeemed, plus accrued and unpaid interest, if any, on those 2028 Notes to the redemption date.

The indenture pursuant to which the 2028 Notes were issued includes covenants that, among other things, limit our and our subsidiaries’ ability to incur certain liens, engage in sale and lease-back transactions or consolidate, merge, or transfer all or substantially all of their assets. These covenants are subject to important qualifications and limitations set forth in the indenture.

Upon the occurrence of a change of control, as defined in the indenture, each holder of the 2028 Notes may require us to purchase all or a portion of such holder’s 2028 Notes at a price equal to 101% of their principal amount, plus accrued and unpaid interest, if any, to, but excluding, the repurchase date.

The indenture also provides for events of default which, if any of them occurs, would permit or require the principal of, premium, if any, and accrued interest, if any, on the 2028 Notes to become or to be declared due and payable.

Commitments— As of June 30, 2019, we maintained letters of credit in the aggregate amount of $63.4 million primarily 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, 2019, no amounts had been drawn under the letters of credit.

As of June 30, 2019, we had commitments to purchase major equipment and make investments totaling approximately $72.8 million for our drilling, pressure pumping, directional drilling and oilfield rentals businesses.

Our pressure pumping business has entered into agreements to purchase minimum quantities of proppants and chemicals from certain vendors. The agreements expire in years 2019 through 2023. As of June 30, 2019, the remaining obligation under these agreements was approximately $42.2 million, of which approximately $14.9 million relates to purchases required during the remainder of 2019. In the event the required minimum quantities are not purchased during any contract year, we could be required to make a liquidated damages payment to the respective vendor for any shortfall.

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.

Adjusted EBITDA

Adjusted earnings before interest, taxes, depreciation and amortization (“Adjusted EBITDA”) is not defined by accounting principles generally accepted in the United States of America (“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 the performance of our fundamental business activities and a comparison of the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be construed as an alternative to the U.S. GAAP measure of net income (loss). Our computations of Adjusted EBITDA may not be the same as other similarly titled measures of other companies. 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,
	2019			2018			2019			2018
	(in thousands)
Net loss	$	(49,447	)	$	(10,713	)	$	(78,061	)	$	(45,130	)
Income tax benefit		(10,128	)		(8,382	)		(16,732	)		(8,100	)
Net interest expense		11,542			10,307			23,494			22,509
Depreciation, depletion, amortization and impairment		208,688			212,384			423,098			422,276
Adjusted EBITDA	$	160,655		$	203,596		$	351,799		$	391,555

Critical Accounting Policies

In February 2016, the FASB issued an accounting standard update to provide guidance for the accounting for leasing transactions. The standard requires the lessee to recognize a lease liability along with a right-of-use asset for all leases with a term longer than one year. A lessee is permitted to make an accounting policy election by class of underlying asset to not recognize the lease liability and related right-of-use asset for leases with a term of one year or less. We adopted this new leasing guidance effective January 1, 2019 utilizing the modified retrospective approach. See Note 4 to our unaudited condensed consolidated financial statements for additional details of our adoption.

In addition to established accounting policies, our condensed consolidated financial statements are impacted by certain estimates and assumptions made by management.

Recently Issued Accounting Standards

See Note 1 to our unaudited condensed consolidated financial statements for a discussion of recently issued accounting standards.

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 of West Texas Intermediate 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 prices have recovered from the lows experienced in the first quarter of 2016. Oil prices reached a high of $77.41 in June 2018. Oil prices remain volatile, as the closing price of oil reached a fourth quarter 2018 high of $76.40 per barrel on October 3, 2018, before declining by 42% over the course of three months to reach a low of $44.48 per barrel in late December 2018. Oil prices averaged $59.88 per barrel in the second quarter of 2019 and closed at $55.87 on July 22, 2019. U.S. rig counts increased in response to improved oil prices in early 2018. Despite oil prices in the mid-$50s to low-$60s, drilling and pressure pumping activity has recently declined, largely as a result of reduced customer spending.

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, 2019, we would have had exposure to interest rate market risk associated with any borrowings that we had under the Credit Agreement and the Reimbursement Agreement.

Loans under the Credit Agreement bear interest by reference, at our election, to the LIBOR rate or base rate. The applicable margin on LIBOR rate loans varies from 1.00% to 2.00% and the applicable margin on base rate loans varies from 0.00% to 1.00%, in each case determined based on our credit rating. As of June 30, 2019, the applicable margin on LIBOR rate loans was 1.5% and the applicable margin on base rate loans was 0.5%. As of June 30, 2019, we had no amounts outstanding under our revolving credit facility. The interest rate on 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 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, 2019, no amounts had been disbursed under any letters of credit.

We conduct a portion of our business in Canadian dollars. 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 financial condition or results of operations.

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, 2019.

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

PART II — OTHER INFORMATION

ITEM 1. Legal Proceedings

On January 22, 2018, an accident at a drilling site in Pittsburg County, Oklahoma resulted in the losses of life of five people, including three of our employees. The EPA, OSHA and the CSB initiated investigations related to this accident. We have cooperated with each of these agencies during its investigation. Our last communication with the EPA was in February 2018. On June 12, 2019, the CSB released its investigation report and issued 19 operational-related recommendations to eight different parties, including five recommendations to us.

On July 18, 2018, OSHA issued a citation containing alleged violations, proposed abatement dates and an aggregate proposed penalty of approximately $74,000. We have filed a notice of contest with OSHA that contests all citation items, abatement dates and proposed penalties. The Department of Labor filed a complaint on OSHA’s behalf seeking enforcement of the citation as issued. We have filed an answer to the complaint and are litigating our contest of the citation items. The ultimate resolution of the OSHA citation items is not known at this time, and we are unable to determine what alleged violations and proposed penalties will be modified or eliminated, if any.

Lawsuits have been filed in the District Court for Pittsburg County, Oklahoma in connection with the five individuals who lost their lives and one of our employees who was injured in the accident. The lawsuits were consolidated for discovery purposes under Cause No. CJ-2018-60 (the “Litigation”). We have finalized settlement agreements with each of the plaintiffs who brought wrongful death lawsuits, and we have been dismissed from those lawsuits. The remaining lawsuit by our surviving employee alleges various causes of action against us including negligence, negligence per se, gross negligence and intentional conduct, and the plaintiff seeks an unspecified amount of damages, including punitive or exemplary damages, costs, interest, and other relief. We dispute the plaintiff’s allegations against us and intend to continue to defend ourselves vigorously. Based on the information we have available as of the date of this Report, we believe that we have adequate insurance to cover the Litigation. However, if this accident is not fully covered by insurance or an enforceable and recoverable indemnity from a third party, it could have a material adverse effect on our business, financial condition, cash flows and results of operations.

Additionally, 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, 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, 2019.

							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⁽¹⁾		Share		or Programs		thousands)⁽²⁾
April 2019		808,534	$	14.54		—	$	174,890
May 2019		—	$	—		—	$	174,890
June 2019		6,471,573	$	11.82		6,336,996	$	99,890
Total		7,280,107				6,336,996	$	99,890

⁽¹⁾

We withheld 912,098 shares in the second quarter with respect to the exercise price and employees’ tax withholding obligations upon the exercise of stock options and the employees’ tax withholding obligations upon the settlement of performance unit awards and the vesting of restricted stock and restricted stock units. These shares were acquired at fair market value pursuant to the terms of the Patterson-UTI Energy, Inc. Amended and Restated 2014 Long-Term Incentive Plan and not pursuant to the stock buyback program.

⁽²⁾

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. On July 26, 2018, we announced that our Board of Directors approved an increase of the authorization under the stock buyback program to allow for $250 million of future share repurchases. On February 7, 2019, we announced that our Board of Directors approved another increase of the authorization under the stock buyback program to allow for $250 million of future share repurchases. All purchases executed to date have been through open market transactions. Purchases under the program are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Purchases may be made at any time without prior notice. Shares of stock purchased under the buyback program are held as treasury shares. There is no expiration date associated with the buyback program. On July 25, 2019, we announced that our Board of Directors approved another increase of the authorization under the stock buyback program to allow for $250 million of future share repurchases.

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		Certificate of 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		Certificate of Elimination with respect to Series A Participating Preferred Stock (filed October 27, 2011 as Exhibit 3.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference).

3.4		Certificate of Amendment to Restated Certificate of Incorporation, as amended (filed July 30, 2018 as Exhibit 3.4 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2018 and incorporated herein by reference).

3.5		Fourth Amended and Restated Bylaws of Patterson-UTI Energy, Inc., effective February 6, 2019 (filed February 12, 2019 as Exhibit 3.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference).

10.1		Patterson-UTI Energy, Inc. 2014 Long-Term Incentive Plan, as amended and restated and further amended effective June 6, 2019 (filed June 6, 2019 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference).

31.1*		Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended.

31.2*		Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended.

32.1*		Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 USC Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS*		XBRL Instance Document – the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH*		XBRL Taxonomy Extension Schema Document
101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*		XBRL Taxonomy Extension Label Linkbase Document
101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document

*	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/ C. Andrew Smith
		C. Andrew Smith
		Executive Vice President and
		Chief Financial Officer
		(Principal Financial and Accounting Officer and Duly Authorized Officer)

Date: July 29, 2019