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 September 30, 2019

or

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

For the transition period from                     to
Commission file number 0-22664

Patterson-UTI Energy, Inc.

(Exact name of registrant as specified in its charter)

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

194,541,625 shares of common stock, $0.01 par value, as of October 24, 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	30
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	43
ITEM 4.	Controls and Procedures	44
	PART II — OTHER INFORMATION
ITEM 1.	Legal Proceedings	45
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	46
ITEM 6.	Exhibits	47
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)

	September 30,			December 31,
	2019			2018
ASSETS
Current assets:
Cash and cash equivalents	$	164,829		$	245,029
Accounts receivable, net of allowance for doubtful accounts of $4,648 and $2,312    at September 30, 2019 and December 31, 2018, respectively		411,145			558,817
Federal and state income taxes receivable		5,991			4,110
Inventory		37,334			65,579
Other		58,261			76,662
Total current assets		677,560			950,197
Property and equipment, net		3,433,495			4,002,549
Right of use asset		23,613			—
Goodwill and intangible assets		449,308			477,640
Deposits on equipment purchases		7,253			12,040
Other		17,864			27,440
Total assets	$	4,609,093		$	5,469,866
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	208,801		$	288,962
Federal and state income taxes payable		535			1,408
Accrued liabilities		220,638			235,946
Lease liability		8,884			—
Total current liabilities		438,858			526,316
Long-term lease liability		20,395			—
Long-term debt, net of debt discount and issuance costs of $5,091 and $5,795    at September 30, 2019 and December 31, 2018, respectively		969,909			1,119,205
Deferred tax liabilities, net		226,663			306,161
Other		10,282			12,761
Total liabilities		1,666,107			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 269,223,800 and    267,315,526 issued and 194,514,730 and 213,614,430 outstanding at    September 30, 2019 and December 31, 2018, respectively		2,692			2,673
Additional paid-in capital		2,866,412			2,827,154
Retained earnings		1,388,691			1,753,557
Accumulated other comprehensive income		5,133			2,487
Treasury stock, at cost, 74,709,070 and 53,701,096 shares at    September 30, 2019 and December 31, 2018, respectively		(1,319,942	)		(1,080,448	)
Total stockholders' equity		2,942,986			3,505,423
Total liabilities and stockholders' equity	$	4,609,093		$	5,469,866

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

3

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited, in thousands, except per share data)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2019			2018			2019			2018
Operating revenues:
Contract drilling	$	317,035		$	365,280		$	1,037,565		$	1,043,005
Pressure pumping		208,637			421,606			707,246			1,253,693
Directional drilling		47,037			51,556			150,214			152,877
Other		25,743			29,036			83,363			81,485
Total operating revenues		598,452			867,478			1,978,388			2,531,060
Operating costs and expenses:
Contract drilling		188,934			226,373			609,928			656,630
Pressure pumping		176,306			342,498			585,191			1,006,353
Directional drilling		56,215			44,740			143,919			126,114
Other		31,759			20,447			71,144			55,705
Depreciation, depletion, amortization and impairment		400,764			281,652			823,862			703,928
Impairment of goodwill		17,800			—			17,800			—
Selling, general and administrative		34,231			32,820			101,680			101,300
Provision for bad debts		—			—			3,594			—
Merger and integration expenses		—			—			—			2,738
Other operating expenses (income), net		(252	)		(771	)		83			(10,321	)
Total operating costs and expenses		905,757			947,759			2,357,201			2,642,447
Operating loss		(307,305	)		(80,281	)		(378,813	)		(111,387	)
Other income (expense):
Interest income		1,693			817			4,481			4,600
Interest expense, net of amount capitalized		(20,739	)		(12,376	)		(47,021	)		(38,668	)
Other		119			281			328			666
Total other expense		(18,927	)		(11,278	)		(42,212	)		(33,402	)
Loss before income taxes		(326,232	)		(91,559	)		(421,025	)		(144,789	)
Income tax benefit		(64,513	)		(16,517	)		(81,245	)		(24,617	)
Net loss	$	(261,719	)	$	(75,042	)	$	(339,780	)	$	(120,172	)
Net loss per common share:
Basic	$	(1.31	)	$	(0.34	)	$	(1.65	)	$	(0.55	)
Diluted	$	(1.31	)	$	(0.34	)	$	(1.65	)	$	(0.55	)
Weighted average number of common shares outstanding:
Basic		199,343			218,059			206,191			219,635
Diluted		199,343			218,059			206,191			219,635
Cash dividends per common share	$	0.04		$	0.04		$	0.12		$	0.10

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

4

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(unaudited, in thousands)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2019			2018			2019			2018
Net loss	$	(261,719	)	$	(75,042	)	$	(339,780	)	$	(120,172	)
Other comprehensive income (loss), net of taxes of $0 for all periods:
Foreign currency translation adjustment		854			1,520			2,646			(1,994	)
Total comprehensive loss	$	(260,865	)	$	(73,522	)	$	(337,134	)	$	(122,166	)

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

5

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		—			—		—			(339,780	)		—		—			(339,780	)
Foreign currency translation adjustment		—			—		—			—			2,646		—			2,646
Exercise of stock options		700			7		9,212			—			—		—			9,219
Vesting of restricted stock units		1,210		12			(12	)		—			—		—			—
Forfeitures of restricted stock		(2	)		—		—			—			—		—			—
Stock-based compensation		—			—		30,058			—			—		—			30,058
Payment of cash dividends		—			—		—			(24,690	)		—		—			(24,690	)
Dividend equivalents		—			—		—			(396	)		—		—			(396	)
Purchase of treasury stock		—			—		—			—			—		(239,494	)		(239,494	)
Balance, September 30, 2019		269,224		$	2,692	$	2,866,412		$	1,388,691		$	5,133	$	(1,319,942	)	$	2,942,986

												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		—			—		—			(120,172	)		—			—			(120,172	)
Foreign currency translation adjustment		—			—		—			—			(1,994	)		—			(1,994	)
Exercise of stock options		40			1		484			—			—			—			485
Issuance of common stock		381			4		(4	)		—			—			—			—
Vesting of restricted stock units		416			4		(4	)		—			—			—			—
Forfeitures of restricted stock		(6	)		—		—			—			—			—			—
Stock-based compensation		—			—		28,449			—			—			—			28,449
Payment of cash dividends		—			—		—			(21,960	)		—			—			(21,960	)
Dividend equivalents		—			—		—			(219	)		—			—			(219	)
Purchase of treasury stock		—			—		—			—			—			(111,655	)		(111,655	)
Balance, September 30, 2018		267,090		$	2,671	$	2,814,748		$	1,963,546		$	4,828		$	(1,030,366	)	$	3,755,427

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

6

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited, in thousands)

	Nine Months Ended
	September 30,
	2019			2018
Cash flows from operating activities:
Net loss	$	(339,780	)	$	(120,172	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, amortization and impairment		823,862			703,928
Impairment of goodwill		17,800			—
Dry holes and abandonments		94			569
Deferred income tax benefit		(79,498	)		(24,617	)
Stock-based compensation expense		30,058			28,449
Net gain on asset disposals		(11,153	)		(21,186	)
Write-down of capacity reservation contract		12,673			—
Provision for bad debts		3,594			—
Amortization of debt discount and issuance costs		668			607
Loss on early debt extinguishment		8,247			—
Changes in operating assets and liabilities:
Accounts receivable		144,210			(67,975	)
Income taxes receivable/payable		(2,754	)		3,275
Inventory and other assets		42,092			(8,022	)
Accounts payable		(44,270	)		(31,935	)
Accrued liabilities		(16,993	)		25,480
Other liabilities		(5,009	)		345
Net cash provided by operating activities		583,841			488,746
Cash flows from investing activities:
Acquisitions, net of cash acquired		(13	)		(3,800	)
Purchases of property and equipment		(283,288	)		(480,568	)
Proceeds from disposal of assets and insurance claims		32,434			28,008
Collection of note receivable		—			23,760
Net cash used in investing activities		(250,867	)		(432,600	)
Cash flows from financing activities:
Purchases of treasury stock		(230,275	)		(111,655	)
Proceeds from exercise of options		—			485
Dividends paid		(24,690	)		(21,960	)
Debt issuance costs		(150	)		(4,469	)
Proceeds from long-term debt		150,000			521,194
Repayment of long-term debt		(308,061	)		—
Proceeds from borrowings under revolving credit facility		—			79,000
Repayment of borrowings under revolving credit facility		—			(347,000	)
Net cash provided by financing activities		(413,176	)		115,595
Effect of foreign exchange rate changes on cash		2			(537	)
Net increase in cash and cash equivalents		(80,200	)		171,204
Cash and cash equivalents at beginning of period		245,029			42,828
Cash and cash equivalents at end of period	$	164,829		$	214,032
Supplemental disclosure of cash flow information:
Net cash (paid) received during the period for:
Interest, net of capitalized interest of $548 in 2019 and $1,094 in 2018	$	(43,281	)	$	(27,306	)
Income taxes		(861	)		3,277
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		(35,941	)	$	60,545
Net (increase) decrease in deposits on equipment purchases		4,787			(2,707	)
Cashless exercise of stock options		9,219			—

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

7

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 nine months ended September 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 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 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.

8

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). The CECL model utilizes a lifetime expected credit loss measurement objective for the recognition of credit losses on financial instruments at the time the asset is originated or acquired. This update will apply to receivables arising from revenue transactions such as contract assets and accounts receivables. This update is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted. The Company plans to adopt this new guidance on January 1, 2020 and does not expect this new guidance will have a significant impact 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 capitalized implementation costs of a hosting arrangement that is a service contract will be expensed over the term of the hosting arrangement. The amendments in the update are effective for public business entities for fiscal years beginning after December 15, 2019, with early adoption permitted. The guidance allows adoption using a retrospective or prospective method. The Company plans to adopt this new guidance on January 1, 2020 prospectively with respect to all implementation costs incurred after the date of adoption and is currently in the process of accumulating all necessary information and 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 update is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted. The Company plans to adopt this new guidance on January 1, 2020 and expects no material impact on its consolidated financial statements.

During the third quarter of 2019, the Company identified and recorded out-of-period adjustments primarily related to the accounting for inventory in its directional drilling segment. The Company concluded that these adjustments were not material to the consolidated financial statements for any of the current or prior periods presented. The net adjustment is reflected as a $14.5 million and $6.6 million increase to “Loss before income taxes” in the condensed consolidated statements of operations for the three and nine month periods ended September 30, 2019, respectively.

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.

9

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 $407 million and $554 million as of September 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.

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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 nine months ended September 30, 2019 and 2018, approximately $0.9 million and $1.0 million, respectively, was amortized and recorded in drilling revenue.

Total contract liability balances were $6.6 million and $7.6 million as of September 30, 2019 and December 31, 2018, respectively. Contract liability balances are included in “Accounts payable” and “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 3 months to 9 years as of September 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.    

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• 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 nine months ended September 30, 2019 (in thousands):

	Three Months Ended		Nine Months Ended
	September 30, 2019		September 30, 2019
Operating lease cost	$	2,447	$	8,241
Short-term lease expense (1)		39		426
Total lease expense	$	2,486	$	8,667

⁽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 nine months ended September 30, 2019 is as follows (in thousands):

	Nine Months Ended
	September 30, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	7,459
Right of use assets obtained in exchange for lease obligations:
Operating leases	$	928

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

	September 30, 2019
Weighted Average Remaining Lease Term:
Operating leases	4.8 years
Weighted Average Discount Rate:
Operating leases		4.5	%

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

Year ending December 31,
2019 (excluding the nine months ended September 30, 2019)	$	2,682
2020		9,317
2021		6,665
2022		4,707
2023		2,663
Thereafter		6,552
Total lease payments		32,586
Less imputed interest		(3,307	)
Total	$	29,279

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

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5. Inventory

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

	September 30, 2019		December 31, 2018
Finished goods	$	62	$	347
Work-in-process		1,092		6,375
Raw materials and supplies		36,180		58,857
Inventory	$	37,334	$	65,579

6. Property and Equipment

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

	September 30, 2019			December 31, 2018
Equipment	$	8,165,044		$	8,370,933
Oil and natural gas properties		223,526			219,855
Buildings		189,568			186,736
Land		26,618			26,144
Total property and equipment		8,604,756			8,803,668
Less accumulated depreciation, depletion and impairment		(5,171,261	)		(4,801,119	)
Property and equipment, net	$	3,433,495		$	4,002,549

On a periodic basis, the Company evaluates its fleet of drilling rigs for marketability based on the condition of inactive rigs, expenditures that would be necessary to bring them to working condition and the expected demand for drilling services by rig type.  The components comprising rigs that will no longer be marketed are evaluated, and those components with continuing utility to the Company’s other marketed rigs are transferred to other rigs or to the Company’s yards to be used as spare equipment.  The remaining components of these rigs are retired. During the three months ended September 30, 2019, the Company identified 36 legacy non-APEX® rigs and related equipment that would be retired. Based on the strong customer preference across the industry for super-spec drilling rigs, the Company believes the 36 rigs that were retired have limited commercial opportunity. The three and nine months ended September 30, 2019 include a charge of $173 million related to this retirement. During the three months ended September 30, 2018, the Company identified 42 legacy non-APEX® rigs and related equipment that would be retired.  Based on the strong customer preference across the industry for super-spec drilling rigs, the Company believed the 42 rigs that were retired had limited commercial opportunity. The three and nine months ended September 30, 2018 included a charge of $48.4 million related to this retirement.

The Company also periodically evaluates its pressure pumping assets for marketability based on the condition of inactive equipment, expenditures that would be necessary to bring the equipment to working condition and the expected demand. The components of equipment that will no longer be marketed are evaluated, and those components with continuing utility will be used as parts to support active equipment. The remaining components of this equipment are retired. During the three months ended September 30, 2019, the Company recorded a charge of $20.5 million for the write-down of pressure pumping equipment compared to a $17.4 million write-down of pressure pumping equipment during the three months ended September 30, 2018.

The Company also periodically evaluates its directional drilling assets, and during the three months ended September 30, 2019, the Company recorded a charge of $8.4 million for the write-down of directional drilling equipment. There were no similar charges in the comparable period of 2018.

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.

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Due to the decline in the market price of the Company’s common stock and recent commodity prices, the Company’s results of operations for the three months ended September 30, 2019 and management’s expectations of operating results in future periods, the Company lowered its expectations with respect to future activity levels in certain of its operating segments. The Company deemed it necessary to assess the recoverability of its contract drilling, pressure pumping, directional drilling and oilfield rentals asset groups.   The Company performed an analysis as required by ASC 360-10-35 to assess the recoverability of the asset groups within its contract drilling, pressure pumping, directional drilling and oilfield rentals operating segments. With respect to these asset groups, future cash flows were estimated over the expected remaining life of the assets, and the Company determined that, on an undiscounted basis, expected cash flows exceeded the carrying value of the asset groups, and no impairment was indicated. Expected cash flows, on an undiscounted basis, exceeded the carrying values of the asset groups within the contract drilling, pressure pumping, directional drilling and oilfield rentals operating segments by approximately 35%, 54%, 23% and 7%, respectively.  

For the assessment performed in the third quarter of 2019, the expected cash flows for the Company’s asset groups included utilization, revenue and costs for the Company’s equipment and services that were estimated based upon the Company’s existing contract backlog, as well as recent contract tenders and customer inquiries. Also, the expected cash flows for the contract drilling, pressure pumping, directional drilling and oilfield rentals asset groups were based on the assumption that activity levels in all four segments would generally be lower than levels experienced in the third quarter of 2019 and would begin to recover in late 2020 or 2021 in response to improved oil prices. While the Company believes these assumptions with respect to future oil pricing are reasonable, actual future prices may vary significantly from the ones that were assumed. The timeframe over which oil prices may recover is highly uncertain. 

All of these factors are beyond the Company’s control. If the lower oil price environment experienced in 2019 were to last into late 2021 and beyond, the Company’s actual cash flows would likely be less than the expected cash flows used in these assessments and could result in impairment charges in the future, and such impairment could be material.  

7. Goodwill and Intangible Assets

Goodwill — Goodwill by operating segment as of September 30, 2019 and changes for the nine 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
Impairment		—		(17,800	)		(17,800	)
Balance at end of period	$	395,060	$	-		$	395,060

The changes to goodwill in Other Operations was primarily 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 operating segment as of September 30, 2019 or December 31, 2018. There were $17.8 million in accumulated impairment losses related to goodwill in the other operations segment as of September 30, 2019 and no accumulated impairment losses for the period ended 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.

Due to the decline in the market price of the Company’s common stock and recent commodity prices, the Company’s results of operations for the three months ended September 30, 2019 and management’s expectations of operating results in future periods, the Company lowered its expectations with respect to future activity levels in certain of its operating segments. The Company performed a quantitative impairment assessment of its goodwill as of September 30, 2019. In completing the assessment, the fair value of each reporting unit was estimated using the income valuation method. The estimate of fair value for each reporting unit required the use of significant unobservable inputs, representative of a Level 3 fair value measurement. The inputs included assumptions related to the future performance of the Company’s contract drilling, oilfield rentals and electrical controls and automation reporting units, such as future oil and natural gas prices and projected demand for the Company’s services, and assumptions related to discount rates and long-term growth rates.

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Based on the results of the goodwill impairment test as of September 30, 2019, the fair value of the contract drilling reporting unit exceeded its carrying value by approximately 13% and management concluded that no impairment was indicated in its contract drilling reporting unit; however, impairment was indicated in its oilfield rentals and electrical controls and automation reporting units included in the other operations segment. The Company recognized an impairment charge of $17.8 million in the quarter ended September 30, 2019 associated with the impairment of all the goodwill in its oilfield rentals and electrical controls and automation reporting units. 

While management believes the assumptions used with respect to future oil pricing are reasonable, actual future prices may vary significantly from the ones that were assumed. The timeframe over which oil prices may recover is highly uncertain. If the lower oil price environment experienced in 2019 were to last into late 2021 and beyond, the Company’s actual cash flows would likely be less than the expected cash flows used in these assessments and could result in additional impairment charges in the future and such impairment could be material.

Intangible Assets — The following table presents the gross carrying amount and accumulated amortization of the intangible assets as of September 30, 2019 and December 31, 2018 (in thousands):

	September 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		(17,463	)		10,537	$	28,000	$	(10,719	)	$	17,281
Developed technology		55,772		(12,355	)		43,417		55,772		(6,533	)		49,239
Favorable drilling contracts		—		—			—		22,500		(22,500	)		—
Internal use software		482		(188	)		294		482		(118	)		364
		84,254		(30,006	)		54,248	$	106,754	$	(39,870	)	$	66,884

Amortization expense on intangible assets of approximately $5.3 million and $4.2 million was recorded in the three months ended September 30, 2019 and 2018, respectively. Amortization expense on intangible assets of approximately $12.6 million and $14.5 million was recorded in the nine months ended September 30, 2019 and 2018, respectively.

8. Accrued Liabilities

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

	September 30, 2019		December 31, 2018
Salaries, wages, payroll taxes and benefits	$	54,748	$	58,160
Workers' compensation liability		74,700		83,772
Property, sales, use and other taxes		36,530		25,318
Insurance, other than workers' compensation		8,488		9,531
Accrued interest payable		10,133		15,774
Other		36,039		43,391
Total		220,638	$	235,946

9. Long Term Debt

2019 Term Loan Agreement — On August 22, 2019, the Company entered into a term loan agreement (“Term Loan Agreement”) among the Company, as borrower, Wells Fargo Bank, National Association, as administrative agent and lender and the other lender party thereto. 

The Term Loan Agreement is a committed senior unsecured term loan facility that permits a single borrowing of up to $150 million, which was drawn in full by the Company on September 23, 2019. Subject to customary conditions, the Company may request that the lenders’ aggregate commitments be increased by up to $75 million, not to exceed total commitments of $225 million. The maturity date under the Term Loan Agreement is June 10, 2022.

Loans under the Term Loan 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 1.375%, and the applicable margin on base rate loans varies from 0.00% to 0.375%, in each case determined based upon the Company’s credit rating. As of September 30, 2019, the applicable margin on LIBOR rate loans and base rate loans was 1.125% and 0.125%, respectively.

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The Term Loan 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 Term Loan Agreement) greater than or equal to 1.50 to 1.00 immediately before and immediately after making any restricted payment.  

The Term Loan Agreement requires mandatory prepayment in an amount equal to 100% of the net cash proceeds from the issuance of new senior indebtedness (other than certain permitted indebtedness) if the Company’s credit rating is below investment grade. The Term Loan Agreement also requires that the Company’s total debt to capitalization ratio, expressed as a percentage, not exceed 50%. The Term Loan Agreement generally defines the total 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 September 30, 2019, the Company had $150 million in borrowings outstanding under the Term Loan Agreement at a LIBOR interest rate of 3.171%.

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 total 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 September 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 September 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 September 30, 2019, the Company had $63.3 million in letters of credit outstanding under the Reimbursement Agreement.

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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 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 bore interest at a rate of 4.97% per annum. On September 25, 2019, the Company fully prepaid the Series A Notes. The total amount of the prepayment, including the applicable “make-whole” premium, was approximately $308 million, which represents 100% of the principal and the “make-whole” premium to the prepayment date. Primarily as a result of the “make-whole” premium, the Company incurred a $8.2 million loss on early extinguishment of the Series A Notes in the three months ended September 30, 2019, which was included in “Interest expense, net of amount capitalized” in the condensed consolidated statements of operations.

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

The note purchase agreement requires compliance with two financial covenants. The Company must not permit its debt to capitalization ratio to exceed 50% at any time. The note purchase agreement generally defines the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. The Company also must not permit its interest coverage ratio as of the last day of a fiscal quarter to be less than 2.50 to 1.00. The note purchase agreement generally defines 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 September 30, 2019.

Events of default under the note purchase agreement include failure to pay principal or interest when due, failure to comply with the financial and operational covenants, a cross default event, a judgment in excess of a threshold event, the guaranty agreement ceasing to be enforceable, the occurrence of certain ERISA events, a change of control event and bankruptcy and other insolvency events. If an event of default under the note purchase agreement occurs and is continuing, then holders of a majority in principal amount of the notes have the right to declare all the notes then-outstanding to be immediately due and payable. In addition, if 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.

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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 $526,000 and $356,000 for the three months ended September 30, 2019 and 2018, respectively and $1.2 million and $1.6 million for the nine months ended September 30, 2019 and 2018, respectively. Amortization of debt issuance costs for the three and nine months ended September 30, 2019 includes $185,000 of debt issuance costs that were expensed as a result of the Series A Notes prepayment. Amortization of debt issuance costs for the nine months ended September 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 September 30, 2019 (in thousands):

Year ending December 31,
2019	$	—
2020		—
2021		—
2022		450,000
2023		—
Thereafter		525,000
Total	$	975,000

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10. Commitments and Contingencies

As of September 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 September 30, 2019, no amounts had been drawn under the letters of credit.

As of September 30, 2019, the Company had commitments to purchase major equipment and make investments totaling approximately $63.3 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 September 30, 2019, the remaining obligation under these agreements was approximately $44.9 million, of which approximately $7.2 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 substantially decreased since 2017, the Company purchased lower cost sand outside of this capacity reservation contract and recorded a charge of $12.7 million in the second quarter of 2019 to revalue the deposit to its expected realizable value.

On July 18, 2018, OSHA issued a citation containing alleged violations, proposed abatement dates and an aggregate proposed penalty of approximately $74,000 in connection with an accident at a drilling site in Pittsburg County, Oklahoma that resulted in the losses of life of five people, including three of the Company’s employees. The Company filed a notice of contest with OSHA that contested all citation items, abatement dates and proposed penalties. The Department of Labor (the “DOL”) filed a complaint on OSHA’s behalf seeking enforcement of the citation as issued, and the Company filed an answer to the complaint.  In October 2019, the Company and the DOL agreed to a settlement of all but one of the citation items, and a hearing on the remaining citation item was held before an administrative law judge. The Company and the DOL will file post-hearing briefs and await the judge’s determination.

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 nine months ended September 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
Paid on September 19, 2019		0.04		7,847
Total cash dividends	$	0.12		24,690

2018:	Per Share		Total
			(in thousands)
Paid on March 22, 2018	$	0.02	$	4,443
Paid on June 21, 2018		0.04		8,832
Paid on September 20, 2018		0.04		8,685
Total cash dividends	$	0.10	$	21,960

On October 23, 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 December 19, 2019 to holders of record as of December 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.

19

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. 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. 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 September 30, 2019, the Company had remaining authorization to purchase approximately $175 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.

The Company acquired shares of stock from employees during the first three 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 nine months ended September 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		19,961,344		225,109
Acquisitions pursuant to long-term incentive plan		1,015,617		14,014
Other		31,013		371
Treasury shares at end of period		74,709,070	$	1,319,942

20

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

	For the nine months ended September 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
Net loss		—			—		—			(261,719	)		—		—			(261,719	)
Foreign currency translation adjustment		—			—		—			—			854		—			854
Vesting of restricted stock units		433			4		(4	)		—			—		—			—
Stock-based compensation		—			—		9,670			—			—		—			9,670
Payment of cash dividends		—			—		—			(7,847	)		—		—			(7,847	)
Dividend equivalents		—			—		—			(160	)		—		—			(160	)
Purchase of treasury stock		—			—		—			—			—		(76,123	)		(76,123	)
Balance, September 30, 2019		269,224		$	2,692	$	2,866,412		$	1,388,691		$	5,133	$	(1,319,942	)	$	2,942,986

21

	For the nine months ended September 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
Net loss		—			—		—			(75,042	)		—			—			(75,042	)
Foreign currency translation adjustment		—			—		—			—			1,520			—			1,520
Vesting of restricted stock units		406			4		(4	)		—			—			—			—
Forfeitures of restricted stock		(4	)		—		—			—			—			—			—
Stock-based compensation		—			—		9,177			—			—			—			9,177
Payment of cash dividends		—			—		—			(8,685	)		—			—			(8,685	)
Dividend equivalents		—			—		—			(106	)		—			—			(106	)
Purchase of treasury stock		—			—		—			—			—			(51,776	)		(51,776	)
Balance, September 30, 2018		267,090		$	2,671	$	2,814,748		$	1,963,546		$	4,828		$	(1,030,366	)	$	3,755,427

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 nine months ended September 30, 2019 or 2018.

Stock option activity from January 1, 2019 to September 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		(15,000	)	$	14.41
Outstanding at September 30, 2019		4,786,150		$	20.59
Exercisable at September 30, 2019		4,756,150		$	20.60

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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 September 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		(319,444	)	$	21.35
Forfeited		(1,500	)	$	21.71
Non-vested restricted stock outstanding at September 30, 2019		115,280		$	21.59

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 September 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		(986,774	)		(38,000	)	$	19.39
Forfeited		(232,170	)		—		$	17.67
Non-vested restricted stock units outstanding at September 30, 2019		2,888,712			397,315		$	15.90

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.

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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 September 30, 2019	$	830	$	667	$	482	NA		NA
Three months ended September 30, 2018	NA		$	667	$	482	$	321	NA
Nine months ended September 30, 2019	$	1,660	$	2,001	$	1,445	$	321	NA
Nine months ended September 30, 2018	NA		$	1,334	$	1,445	$	963	$	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 September 30, 2019 was 19.8%, compared with 18.0% for the three months ended September 30, 2018. The higher effective income tax rate for the three months ended September 30, 2019 was primarily attributable to U.S. Tax Reform, which provided for a one-time transition tax on foreign earnings that were previously tax deferred, which was booked during the third quarter of 2018.

The Company’s effective income tax rate for the nine months ended September 30, 2019 was 19.3%, compared with 17.0% for the nine months ended September 30, 2018. The higher effective income tax rate for the nine months ended September 30, 2019 was primarily attributable to U.S. Tax Reform, which provided for a one-time transition tax on foreign earnings that were previously tax deferred, which was booked during the third quarter of 2018, as well as the impact of non-U.S. valuation allowances booked in 2018.  The Company also recorded tax expense related to share-based compensation during the third quarter of 2019.

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 and 2019 to be finalized during 2019 and 2020. 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.

24

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 nine months ended September 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						Nine Months Ended
	September 30,						September 30,
	2019			2018			2019			2018
BASIC EPS:
Net loss attributed to common stockholders	$	(261,719	)	$	(75,042	)	$	(339,780	)	$	(120,172	)
Weighted average number of common shares outstanding, excluding    non-vested shares of restricted stock		199,343			218,059			206,191			219,635
Basic net loss per common share	$	(1.31	)	$	(0.34	)	$	(1.65	)	$	(0.55	)
DILUTED EPS:
Net loss attributed to common stockholders	$	(261,719	)	$	(75,042	)	$	(339,780	)	$	(120,172	)
Weighted average number of common shares outstanding, excluding    non-vested shares of restricted stock		199,343			218,059			206,191			219,635
Add dilutive effect of potential common shares		—			—			—			—
Weighted average number of diluted common shares outstanding		199,343			218,059			206,191			219,635
Diluted net loss per common share	$	(1.31	)	$	(0.34	)	$	(1.65	)	$	(0.55	)
Potentially dilutive securities excluded as anti-dilutive		9,753			9,052			9,753			9,052

15. Business Segments

At September 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.

25

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2019			2018			2019			2018
Revenues:
Contract drilling	$	317,468		$	365,697		$	1,038,705		$	1,044,190
Pressure pumping		208,637			421,606			707,246			1,253,693
Directional drilling		47,037			51,556			150,214			152,877
Other operations (1)		32,809			33,087			96,052			94,457
Elimination of intercompany revenues (2)		(7,499	)		(4,468	)		(13,829	)		(14,157	)
Total revenues	$	598,452		$	867,478		$	1,978,388		$	2,531,060
Income (loss) before income taxes:
Contract drilling	$	(169,528	)	$	(42,704	)	$	(131,817	)	$	(60,058	)
Pressure pumping		(42,962	)		(1,487	)		(76,138	)		44,539
Directional drilling		(32,501	)		(8,995	)		(43,458	)		(21,586	)
Other operations		(39,192	)		(4,861	)		(51,713	)		(13,727	)
Corporate		(23,374	)		(23,005	)		(72,010	)		(70,876	)
Other operating (expenses) income, net (3)		252			771			(83	)		10,321
Provision for bad debts		—			—			(3,594	)		—
Interest income		1,693			817			4,481			4,600
Interest expense		(20,739	)		(12,376	)		(47,021	)		(38,668	)
Other		119			281			328			666
Loss before income taxes	$	(326,232	)	$	(91,559	)	$	(421,025	)	$	(144,789	)
Depreciation, depletion, amortization and impairment:
Contract drilling	$	296,119		$	179,979		$	554,838		$	441,834
Pressure pumping		72,139			76,986			188,459			191,370
Directional drilling		20,518			12,263			41,755			35,039
Other operations		10,227			10,545			33,472			29,688
Corporate		1,761			1,879			5,338			5,997
Total depreciation, depletion, amortization and impairment	$	400,764		$	281,652		$	823,862		$	703,928
Capital expenditures:
Contract drilling	$	34,752		$	103,295		$	158,141		$	299,637
Pressure pumping		19,826			44,860			90,028			125,978
Directional drilling		5,559			6,855			11,121			29,718
Other operations		7,191			6,817			21,194			23,524
Corporate		700			958			2,804			1,711
Total capital expenditures	$	68,028		$	162,785		$	283,288		$	480,568

	September 30, 2019		December 31, 2018
Identifiable assets:
Contract drilling	$	3,308,588	$	3,817,638
Pressure pumping	$	752,267		921,237
Directional drilling	$	175,534		239,341
Other operations	$	132,140		177,374
Corporate (4)	$	240,564		314,276
Total assets	$	4,609,093	$	5,469,866

⁽¹⁾ Other operations includes the Company’s oilfield rentals business, drilling equipment service 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.

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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 September 30, 2019 and December 31, 2018 is set forth below (in thousands):

	September 30, 2019				December 31, 2018
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
3.95% Senior Notes	$	525,000	$	530,284	$	525,000	$	482,488
4.97% Series A Senior Notes		—		—		300,000		300,043
4.27% Series B Senior Notes		300,000		300,071		300,000		293,900
2019 Term Loan		150,000		150,000		—		—
Total debt	$	975,000	$	980,355	$	1,125,000	$	1,076,431

The fair values of the 3.95% Senior Notes at September 30, 2019 and December 31, 2018 are based on discounted cash flows associated with the notes using the 3.81% market rate of interest at September 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 at December 31, 2018 and Series B Notes at September 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 rate used in measuring this fair value was 4.97% at December 31, 2018. For the Series B Notes, the current market rates used in measuring this fair value were 4.08% at September 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. The carrying values of the balance outstanding at September 30, 2019 under the Term Loan Agreement approximated its fair value as the instrument has a floating interest rate.

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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;

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• 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.

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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 service equipment for 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 $56.34 per barrel in the third quarter of 2019 and closed at $53.28 per barrel on October 21, 2019. Despite oil prices in the mid-$50s, drilling and pressure pumping activity has continued to decline, largely as a result of reduced customer spending.

Our average active rig count for the third quarter of 2019 was 142 rigs, which included 142 rigs operating in the United States and less than one rig operating in Canada. This was a decrease from our average active rig count for the second quarter of 2019 of 158, which included 157 rigs in the United States and one rig in Canada. Our customers slowed spending levels during the third quarter, which negatively impacted our activity levels.  We expect our rig count to average 126 rigs in the fourth quarter, with some increase in the first quarter as customer budgets reset in 2020. Based on term contracts (contracts with a duration of six months or more) currently in place, we expect an average of 73 rigs operating under term contracts during the fourth quarter of 2019 and an average of 55 rigs operating under term contracts during the twelve months ending September 30, 2020.

In pressure pumping, we ended the third quarter with 14 active spreads compared to 15 at the end of the second quarter. We idled another spread early in the fourth quarter. As pressure pumping activity is expected to fall further in the fourth quarter, we will continue to evaluate the economics of working versus idling spreads on a spread-by-spread basis.    

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 nine months ended September 30, 2019 and 2018, our operating revenues consisted of the following (dollars in thousands):

	Three Months Ended September 30,								Nine Months Ended September 30,
	2019				2018				2019				2018
Contract drilling	$	317,035	53.0	%	$	365,280	42.1	%	$	1,037,565	52.4	%	$	1,043,005	41.2	%
Pressure pumping		208,637	34.9	%		421,606	48.6	%		707,246	35.7	%		1,253,693	49.5	%
Directional drilling		47,037	7.9	%		51,556	5.9	%		150,214	7.6	%		152,877	6.0	%
Other operations		25,743	4.2	%		29,036	3.4	%		83,363	4.3	%		81,485	3.3	%
	$	598,452	100.0	%	$	867,478	100.0	%	$	1,978,388	100.0	%	$	2,531,060	100.0	%

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Contract Drilling

Contract drilling revenues accounted for 53.0% of our consolidated third quarter 2019 revenues and decreased 13.2% 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 September 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 September 30, 2019 was approximately $646 million. Approximately 35% of the total September 30, 2019 backlog is reasonably expected to remain at September 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 September 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 34.9% of our consolidated third quarter 2019 revenues and decreased 50.5% from the comparable 2018 period. As of September 30, 2019, we had approximately 1.3 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 nine months of 2019. In response to oversupplied market conditions, we further reduced the number of active pressure pumping spreads to 14 as of the end of the third quarter of 2019, and we idled another spread early in the fourth quarter.

Directional Drilling

Directional drilling revenues accounted for 7.9% of our consolidated third quarter 2019 revenues and decreased 8.8% 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 4.2% of our consolidated third quarter 2019 revenues and decreased 11.3% 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 drilling equipment service 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.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Contract drilling	$	(169,528	)	$	(42,704	)	$	(131,817	)	$	(60,058	)
Pressure pumping		(42,962	)		(1,487	)		(76,138	)		44,539
Directional drilling		(32,501	)		(8,995	)		(43,458	)		(21,586	)
Other operations		(39,192	)		(4,861	)		(51,713	)		(13,727	)
Corporate		(23,122	)		(22,234	)		(75,687	)		(60,555	)
	$	(307,305	)	$	(80,281	)	$	(378,813	)	$	(111,387	)

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

Our consolidated net loss for the third quarter of 2019 was $262 million compared to a net loss of $75 million for the third quarter of 2018.

Results of Operations

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

Contract Drilling	2019			2018			% Change
	(dollars in thousands)
Revenues	$	317,035		$	365,280			(13.2	)%
Direct operating costs		188,934			226,373			(16.5	)%
Margin (1)		128,101			138,907			(7.8	)%
Selling, general and administrative		1,510			1,632			(7.5	)%
Depreciation, amortization and impairment		296,119			179,979			64.5	%
Operating loss	$	(169,528	)	$	(42,704	)		297.0	%
Operating days (2)		13,081			16,394			(20.2	)%
Average revenue per operating day	$	24.24		$	22.28			8.8	%
Average direct operating costs per operating day	$	14.44		$	13.81			4.6	%
Average margin per operating day (1)	$	9.79		$	8.47			15.6	%
Average rigs operating		142			178			(20.2	)%
Capital expenditures	$	34,752		$	103,295			(66.4	)%

⁽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 third quarter of 2019, our average number of rigs operating was 142, compared to 178 in the third quarter of 2018. Our average revenue per operating day is largely dependent on the pricing terms of our rig contracts.

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

Depreciation, amortization and impairment for the quarter ended September 30, 2019 included a charge of $173 million relating to the retirement of 36 legacy non-APEX® drilling rigs and related equipment. Depreciation, amortization and impairment for the quarter ended September 30, 2018 included a charge of $48.4 million related to the retirement of 42 legacy non-APEX® drilling rigs and related equipment.  

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

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Pressure Pumping	2019			2018			% Change
	(dollars in thousands)
Revenues	$	208,637		$	421,606			(50.5	)%
Direct operating costs		176,306			342,498			(48.5	)%
Margin (1)		32,331			79,108			(59.1	)%
Selling, general and administrative		3,154			3,609			(12.6	)%
Depreciation, amortization and impairment		72,139			76,986			(6.3	)%
Operating loss	$	(42,962	)	$	(1,487	)		2,789.2	%
Fracturing jobs		126			210			(40.0	)%
Other jobs		173			287			(39.7	)%
Total jobs		299			497			(39.8	)%
Average revenue per fracturing job	$	1,631.71		$	1,978.49			(17.5	)%
Average revenue per other job	$	17.58		$	21.34			(17.6	)%
Average revenue per total job	$	697.78		$	848.30			(17.7	)%
Average direct operating costs per total job	$	589.65		$	689.13			(14.4	)%
Average margin per total job (1)	$	108.13		$	159.17			(32.1	)%
Margin as a percentage of revenues (1)		15.5	%		18.8	%		(17.6	)%
Capital expenditures	$	19,826		$	44,860			(55.8	)%

⁽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 126 fracturing jobs during the third quarter of 2019, compared to 210 fracturing jobs in the third quarter of 2018. Our average revenue per fracturing job was $1.632 million in the third quarter of 2019, compared to $1.978 million in the third quarter of 2018.

Selling, general and administrative expenses decreased primarily as a result of cost reduction efforts.

Depreciation, amortization and impairment included charges of $20.5 million and $17.4 million related to the write-down of pressure pumping equipment in the quarters ended September 30, 2019 and 2018, respectively.

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

Directional Drilling	2019			2018			% Change
	(dollars in thousands)
Revenues	$	47,037		$	51,556			(8.8	)%
Direct operating costs		56,215			44,740			25.6	%
Margin (1)		(9,178	)		6,816		NA
Selling, general and administrative		2,805			3,548			(20.9	)%
Depreciation, amortization, and impairment		20,518			12,263			67.3	%
Operating loss	$	(32,501	)	$	(8,995	)		261.3	%
Capital expenditures	$	5,559		$	6,855			(18.9	)%

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

Directional drilling revenue decreased by $4.5 million from the third quarter of 2018 primarily due to decreased job activity, partially offset by increased revenue from Superior QC, LLC (“Superior QC”), which was acquired in the first quarter of 2018. Direct operating costs for the three months ended September 30, 2019 included a charge of $17.0 million primarily due to the write-down of inventory.

Selling, general and administrative expense decreased from the third quarter of 2018 primarily as a result of cost reduction efforts. Depreciation, amortization and impairment for the three months ended September 30, 2019 included a charge of $8.4 million related to the write-down of directional drilling equipment. There were no similar charges in the comparable period of 2018.

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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	$	25,743		$	29,036			(11.3	)%
Direct operating costs		31,759			20,447			55.3	%
Margin (1)		(6,016	)		8,589		NA
Selling, general and administrative		5,149			2,905			77.2	%
Depreciation, depletion, amortization and impairment		10,227			10,545			(3.0	)%
Impairment of goodwill		17,800			—			100.0	%
Operating loss	$	(39,192	)	$	(4,861	)		706.3	%
Capital expenditures	$	7,191		$	6,817			5.5	%

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

During the quarter ended September 30, 2019, we made the decision to transition away from our engineering and manufacturing efforts in Calgary. Direct operating costs and selling, general and administrative costs for the quarter ended September 30, 2019 include $12.4 million and $2.2 million, respectively, of charges associated with this decision. The $12.4 million of charges to direct operating costs is primarily comprised of inventory write-offs.

All of the goodwill associated with our oilfield rentals and electrical controls and automation reporting units was impaired during the three months ended September 30, 2019. See Note 7 of Notes to unaudited condensed consolidated financial statements for additional information.

Corporate	2019			2018			% Change
	(dollars in thousands)
Selling, general and administrative	$	21,613		$	21,126			2.3	%
Depreciation	$	1,761		$	1,879			(6.3	)%
Other operating expenses (income), net
Net gain on asset disposals	$	(637	)	$	(3,714	)		(82.8	)%
Legal-related expenses and settlements, net of insurance reimbursements		—			1,977			(100.0	)%
Research and development		385			958			(59.8	)%
Other		—			8			(100.0	)%
Other operating expenses (income), net	$	(252	)	$	(771	)		(67.3	)%
Interest income	$	1,693		$	817			107.2	%
Interest expense	$	20,739		$	12,376			67.6	%
Other income	$	119		$	281			(57.7	)%
Capital expenditures	$	700		$	958			(26.9	)%

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. Legal-related expenses and settlements in 2018 includes insurance deductibles and investigation costs related to an accident at a drilling site in January 2018.

Interest expense includes a loss on debt extinguishment of $8.2 million in the third quarter of 2019 as a result of prepayment of the Series A Notes (as discussed and defined in the “Liquidity and Capital Resources” section).

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

Contract Drilling	2019			2018			% Change
	(dollars in thousands)
Revenues	$	1,037,565		$	1,043,005			(0.5	)%
Direct operating costs		609,928			656,630			(7.1	)%
Margin (1)		427,637			386,375			10.7	%
Selling, general and administrative		4,616			4,599			0.4	%
Depreciation, amortization and impairment		554,838			441,834			25.6	%
Operating loss	$	(131,817	)	$	(60,058	)		119.5	%
Operating days		43,253			47,610			(9.2	)%
Average revenue per operating day	$	23.99		$	21.91			9.5	%
Average direct operating costs per operating day	$	14.10		$	13.79			2.2	%
Average margin per operating day (1)	$	9.89		$	8.12			21.8	%
Average rigs operating		158			174			(9.2	)%
Capital expenditures	$	158,141		$	299,637			(47.2	)%

⁽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 nine months of 2019, our average number of rigs operating was 158, compared to 174 in the same period of 2018. Our average rig revenue per operating day was $23,990 in the first nine months of 2019, compared to $21,910 in the first nine months of 2018. Our average revenue per operating day is largely dependent on the pricing terms of our rig contracts.

Revenues decreased due to a decrease in operating days. This was largely offset by higher average revenue per operating day.

Depreciation, amortization and impairment for the nine months ended September 30, 2019 included a charge of $173 million relating to the retirement of 36 legacy non-APEX® drilling rigs and related equipment. Depreciation, amortization and impairment for the nine months ended September 30, 2018 included a charge of $48.4 million related to the retirement of 42 legacy non-APEX® drilling rigs and related equipment.  

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

Pressure Pumping	2019			2018			% Change
	(dollars in thousands)
Revenues	$	707,246		$	1,253,693			(43.6	)%
Direct operating costs		585,191			1,006,353			(41.9	)%
Margin (1)		122,055			247,340			(50.7	)%
Selling, general and administrative		9,734			11,431			(14.8	)%
Depreciation, amortization and impairment		188,459			191,370			(1.5	)%
Operating income (loss)	$	(76,138	)	$	44,539		NA
Fracturing jobs		412			631			(34.7	)%
Other jobs		629			831			(24.3	)%
Total jobs		1,041			1,462			(28.8	)%
Average revenue per fracturing job	$	1,687.39		$	1,958.74			(13.9	)%
Average revenue per other job	$	19.14		$	21.34			(10.3	)%
Average revenue per total job	$	679.39		$	857.52			(20.8	)%
Average direct operating costs per total job	$	562.14		$	688.34			(18.3	)%
Average margin per total job (1)	$	117.25		$	169.18			(30.7	)%
Margin as a percentage of revenues (1)		17.3	%		19.7	%		(12.2	)%
Capital expenditures and acquisitions	$	90,028		$	125,978			(28.5	)%

⁽¹⁾ Margin is defined as revenues less direct operating costs and excludes depreciation, amortization and impairment and selling, general and administrative expenses. Average margin per total job is defined as margin divided by total jobs. Margin as a percentage of revenues is defined as margin divided by revenues.

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We completed 412 fracturing jobs during the first nine months of 2019, compared to 631 fracturing jobs in the same period of 2018. Our average revenue per fracturing job was $1.687 million in the first nine months of 2019, compared to $1.959 million in the first nine months of 2018.

Revenues and direct operating costs during the nine months ended September 30, 2019 decreased primarily due to a decline in the number of fracturing jobs, as compared to the nine months ended September 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.

Depreciation, amortization and impairment included charges of $20.5 million and $17.4 million related to the write-down of pressure pumping equipment in the nine months ended September 30, 2019 and 2018, respectively.

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

Directional Drilling	2019			2018			% Change
	(dollars in thousands)
Revenues	$	150,214		$	152,877			(1.7	)%
Direct operating costs		143,919			126,114			14.1	%
Margin (1)		6,295			26,763			(76.5	)%
Selling, general and administrative		7,998			13,310			(39.9	)%
Depreciation, amortization, and impairment		41,755			35,039			19.2	%
Operating loss	$	(43,458	)	$	(21,586	)		101.3	%
Capital expenditures	$	11,121		$	29,718			(62.6	)%

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

Direct operating costs for the nine months ended September 30, 2019 included a charge of $17.0 million primarily due to the write-down of inventory.

Selling, general and administrative expense decreased in the nine months ended September 30, 2019 primarily as a result of cost reduction efforts. Depreciation, amortization and impairment for the nine months ended September 30, 2019 included a charge of $8.4 million related to the write-down of directional drilling equipment. There were no similar charges in the comparable period of 2018.

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

Other Operations	2019			2018			% Change
	(dollars in thousands)
Revenues	$	83,363		$	81,485			2.3	%
Direct operating costs		71,144			55,705			27.7	%
Margin (1)		12,219			25,780			(52.6	)%
Selling, general and administrative		12,660			9,819			28.9	%
Depreciation, depletion, amortization and impairment		33,472			29,688			12.7	%
Impairment of goodwill		17,800			—			100.0	%
Operating loss	$	(51,713	)	$	(13,727	)		276.7	%
Capital expenditures	$	21,194		$	23,524			(9.9	)%

⁽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 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.

During the quarter ended September 30, 2019, we made the decision to transition away from our engineering and manufacturing efforts in Calgary. Direct operating costs and selling, general and administrative costs for the nine months ended September 30, 2019

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include $12.4 million and $2.2 million, respectively, of charges associated with this decision. The $12.4 million of charges to direct operating costs is primarily comprised of inventory write-offs.

All of the goodwill associated with our oilfield rentals and electrical controls and automation reporting units was impaired during the nine months ended September 30, 2019. See Note 7 of Notes to unaudited condensed consolidated financial statements for additional information.

Corporate	2019			2018			% Change
	(dollars in thousands)
Selling, general and administrative	$	66,672		$	62,141			7.3	%
Merger and integration expenses	$	—		$	2,738			(100.0	)%
Depreciation	$	5,338		$	5,997			(11.0	)%
Other operating expenses (income), net
Net gain on asset disposals	$	(11,153	)	$	(21,186	)		(47.4	)%
Legal-related expenses and settlements, net of insurance reimbursements		(3,471	)		11,298		NA
Research and development		2,111			3,067			(31.2	)%
Other		12,596			(3,500	)	NA
Other operating expenses (income), net	$	83		$	(10,321	)	NA
Provision for bad debts	$	3,594		$	—			100	%
Interest income	$	4,481		$	4,600			(2.6	)%
Interest expense	$	47,021		$	38,668			21.6	%
Other income	$	328		$	666			(50.8	)%
Capital expenditures	$	2,804		$	1,711			63.9	%

Selling, general and administrative expense increased in the nine months ended September 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 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 substantially decreased since 2017, we purchased lower cost sand outside of this capacity reservation contract and revalued the deposit at its expected realizable value. Other operating expenses (income), net includes a $3.5 million gain recorded in 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 were estimated to be uncollectible. Interest expense includes a loss on debt extinguishment of $8.2 million in the third quarter of 2019 as a result of prepayment of the Series A Notes.

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 September 30, 2019 was 19.8%, compared with 18.0% for the three months ended September 30, 2018. The higher effective income tax rate for the three months ended September 30, 2019 was primarily attributable to the enactment of “H.R.1,” also known as the “Tax Cuts and Jobs Act” (“U.S. Tax Reform”), which provided for a one-time transition tax on foreign earnings that were previously tax deferred, which was booked during the third quarter of 2018.  

Our effective income tax rate for the nine months ended September 30, 2019 was 19.3%, compared with 17.0% for the nine months ended September 30, 2018. The higher effective income tax rate for the nine months ended September 30, 2019 was primarily attributable to U.S. Tax Reform, which provided for a one-time transition tax on foreign earnings that were previously tax deferred, which was booked during the third quarter of 2018, as well as the impact of non-U.S. valuation allowances booked in 2018. We also recorded tax expense related to share-based compensation during the third quarter of 2019.  

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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 and 2019 to be finalized during 2019 and 2020. 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 September 30, 2019 included approximately $239 million in working capital, including $165 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.

On August 22, 2019, we entered into a term loan agreement that permits a single borrowing of up to $150 million, which we drew in full on September 23, 2019. Subject to customary conditions, we may request that the lenders’ aggregate commitments be increased by up to $75 million, not to exceed total commitments of $225 million. As described below, on September 25, 2019, we used $150 million of borrowings from the Term Loan Agreement and approximately $158 million of cash on hand to prepay the Series A Notes. The total amount of the prepayment, including the applicable “make-whole” premium, was approximately $308 million, plus accrued interest to the prepayment date.

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 share repurchases and/or debt repayment in the near-term.

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 nine months ended September 30, 2019, our sources of cash flow included:

• $584 million from operating activities

• $32.4 million in proceeds from the disposal of property and equipment and insurance proceeds, and

• $150 million in proceeds from the issuance of long-term debt.

During the nine months ended September 30, 2019, we used $24.7 million to pay dividends on our common stock, $230 million for the repurchases of our common stock, $308 million for the prepayment of the Series A Notes and $283 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 nine months ended September 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
Paid on September 19, 2019		0.04		7,847
	$	0.12	$	24,690

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On October 23, 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 December 19, 2019 to holders of record as of December 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. 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. 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 September 30, 2019, we had remaining authorization to purchase approximately $175 million of our outstanding common stock under the stock buyback program.

Treasury stock acquisitions during the nine months ended September 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		19,961,344		225,109
Acquisitions pursuant to long-term incentive plan (1)		1,015,617		14,014
Other		31,013		371
Treasury shares at end of period		74,709,070	$	1,319,942

⁽¹⁾ We withheld 1,015,617 shares during the first three 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.

2019 Term Loan Agreement — On August 22, 2019, we entered into a term loan agreement (“Term Loan Agreement”) among us, as borrower, Wells Fargo Bank, National Association, as administrative agent and lender and the other lender party thereto.  

The Term Loan Agreement is a committed senior unsecured term loan facility that permits a single borrowing of up to $150 million, which we drew in full on September 23, 2019. Subject to customary conditions, we may request that the lenders’ aggregate commitments be increased by up to $75 million, not to exceed total commitments of $225 million. The maturity date under the Term Loan Agreement is June 10, 2022.

Loans under the Term Loan 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 1.375%, and the applicable margin on base rate loans varies from 0.00% to 0.375%, in each case determined based upon our credit rating. As of September 30, 2019, the applicable margin on LIBOR rate loans and base rate loans was 1.125% and 0.125%, respectively.

The Term Loan 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 Term Loan Agreement) greater than or equal to 1.50 to 1.00 immediately before and immediately after making any restricted payment.  

The Term Loan Agreement requires mandatory prepayment in an amount equal to 100% of the net cash proceeds from the issuance of new senior indebtedness (other than certain permitted indebtedness) if our credit rating is below investment grade. The Term Loan Agreement also requires that our total debt to capitalization ratio, expressed as a percentage, not exceed 50%. The Term Loan Agreement generally defines the total 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 September 30, 2019, we had $150 million in borrowings outstanding under the Term Loan Agreement at a LIBOR interest rate of 3.171%.

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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 total 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 September 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 September 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 September 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. 

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Series A 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 bore interest at a rate of 4.97% per annum. On September 25, 2019, we fully prepaid the Series A Notes. The total amount of the prepayment, including the applicable “make-whole” premium was approximately $308 million, which represents 100% of the principal and the “make-whole” premium to the prepayment date. As a result of the prepayment, we also recorded a $8.2 million loss on early debt extinguishment in the three months ended September 30, 2019, which was included in “Interest expense, net of amount capitalized” in the condensed consolidated statements of operations.

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

The note purchase agreement requires compliance with two financial covenants. We must not permit our debt to capitalization ratio to exceed 50% at any time. The note purchase agreement generally defines the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. We also must not permit our interest coverage ratio as of the last day of a fiscal quarter to be less than 2.50 to 1.00. The note purchase agreement generally defines 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 September 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 agreement include failure to pay principal or interest when due, failure to comply with the financial and operational covenants, a cross default event, a judgment in excess of a threshold event, the guaranty agreement ceasing to be enforceable, the occurrence of certain ERISA events, a change of control event and bankruptcy and other insolvency events. If an event of default under the note purchase agreement occurs and is continuing, then holders of a majority in principal amount of the notes have the right to declare all the notes then-outstanding to be immediately due and payable. In addition, if we default in payments on any note, then until such defaults are cured, the holder thereof may declare all the notes held by it pursuant to the note purchase agreement to be immediately due and payable.

2028 Senior Notes — On January 19, 2018, we completed an offering of $525 million aggregate principal amount of our 3.95% Senior Notes due 2028 (the “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.

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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 September 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 September 30, 2019, no amounts had been drawn under the letters of credit.

As of September 30, 2019, we had commitments to purchase major equipment and make investments totaling approximately $63.3 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 September 30, 2019, the remaining obligation under these agreements was approximately $44.9 million, of which approximately $7.2 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						Nine Months Ended
	September 30,						September 30,
	2019			2018			2019			2018
	(in thousands)
Net loss	$	(261,719	)	$	(75,042	)	$	(339,780	)	$	(120,172	)
Income tax benefit		(64,513	)		(16,517	)		(81,245	)		(24,617	)
Net interest expense		19,046			11,559			42,540			34,068
Depreciation, depletion, amortization and impairment		400,764			281,652			823,862			703,928
Impairment of goodwill		17,800			—			17,800			—
Adjusted EBITDA	$	111,378		$	201,652		$	463,177		$	593,207

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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 $56.34 per barrel in the third quarter of 2019 and closed at $53.28 on October 21, 2019. U.S. rig counts increased in response to improved oil prices in early 2018. Despite oil prices in the mid-$50s, drilling and pressure pumping activity has continued to decline, 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 September 30, 2019, we had exposure to interest rate market risk associated with our borrowings under the Term Loan Agreement, and 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 Term Loan 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 1.375%, and the applicable margin on base rate loans varies from 0.00% to 0.375%, in each case determined based upon our credit rating. As of September 30, 2019, the applicable margin on LIBOR rate loans and base rate loans was 1.125% and 0.125%, respectively. As of September 30, 2019, we had $150 million in borrowings outstanding under the Term Loan Agreement at a LIBOR interest rate of 3.171%.

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 September 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 September 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.

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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 September 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 September 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.

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PART II — OTHER INFORMATION

ITEM 1. Legal Proceedings

On July 18, 2018, OSHA issued a citation containing alleged violations, proposed abatement dates and an aggregate proposed penalty of approximately $74,000 in connection with an accident at a drilling site in Pittsburg County, Oklahoma that resulted in the losses of life of five people, including three of our employees. We filed a notice of contest with OSHA that contested all citation items, abatement dates and proposed penalties. The Department of Labor (the “DOL”) filed a complaint on OSHA’s behalf seeking enforcement of the citation as issued, and we filed an answer to the complaint.  In October 2019, we and the DOL agreed to a settlement of all but one of the citation items, and a hearing on the remaining citation item was held before an administrative law judge. We and the DOL will file post-hearing briefs and await the judge’s determination.

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.

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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 September 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)
July 2019		394,819	$	11.49		320,000	$	246,330
August 2019		4,570,792	$	8.91		4,565,000	$	205,658
September 2019		3,353,884	$	9.20		3,331,216	$	175,000
Total		8,319,495				8,216,216	$	175,000

⁽¹⁾ We withheld 103,279 shares in the third 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. 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. 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.

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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	Term Loan Agreement, dated August 22, 2019, among Patterson-UTI Energy, Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent and lender and the other lender party thereto (filed August 23, 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*	Inline 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*	Inline XBRL Taxonomy Extension Schema Document
101.CAL*	Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	Inline XBRL Taxonomy Extension Presentation Linkbase Document
104	The cover page from the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2019, has been formatted in Inline XBRL.

* filed herewith

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SIGNATURE

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

PATTERSON-UTI ENERGY, INC.
By:	/s/ C. Andrew Smith
	C. Andrew Smith
	Executive Vice President and
	Chief Financial Officer
	(Principal Financial and Accounting Officer and Duly Authorized Officer)

Date: October 30, 2019

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