PATTERSON UTI ENERGY INC - Quarter Report: 2020 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q


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

For the quarterly period ended September 30, 2020


☐		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 1-39270

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
Preferred Stock Purchase Rights		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.

187,493,775 shares of common stock, $0.01 par value, as of October 23, 2020

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	29
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	46
ITEM 4.	Controls and Procedures	47

	PART II — OTHER INFORMATION

ITEM 1.	Legal Proceedings	48
ITEM 1A.	Risk Factors	48
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	50
ITEM 6.	Exhibits	51
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,
	2020			2019
ASSETS
Current assets:
Cash and cash equivalents	$	303,741		$	174,185
Accounts receivable, net of allowance for credit losses of $10,996 and $6,516 at September 30, 2020 and December 31, 2019, respectively		131,329			339,699
Federal and state income taxes receivable		4,778			6,397
Inventory		33,693			36,357
Other		58,569			75,177
Total current assets		532,110			631,815
Property and equipment, net		2,893,172			3,306,677
Right of use asset		17,679			31,275
Goodwill and intangible assets		33,151			444,004
Deposits on equipment purchases		4,728			8,066
Other		10,385			17,778
Total assets	$	3,491,225		$	4,439,615
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	74,367		$	170,475
Federal and state income taxes payable		—			342
Accrued liabilities		181,560			219,850
Lease liability		7,470			9,935
Total current liabilities		263,397			400,602
Long-term lease liability		20,738			26,644
Long-term debt, net of debt discount and issuance costs of $7,634 and $8,460 at September 30, 2020 and December 31, 2019, respectively		967,366			966,540
Deferred tax liabilities, net		102,747			202,959
Other		17,414			9,250
Total liabilities		1,371,662			1,605,995
Commitments and contingencies (see Note 9)
Stockholders' equity:
Preferred stock, par value $0.01; authorized 1,000,000 shares, no shares issued		—			—
Common stock, par value $0.01; authorized 400,000,000 shares with 270,861,290 and 269,372,257 issued and 187,476,087 and 192,035,870 outstanding at September 30, 2020 and December 31, 2019, respectively		2,708			2,694
Additional paid-in capital		2,895,753			2,875,680
Retained earnings		582,360			1,294,902
Accumulated other comprehensive income		5,005			5,478
Treasury stock, at cost, 83,385,203 and 77,336,387 shares at September 30, 2020 and December 31, 2019, respectively		(1,366,263	)		(1,345,134	)
Total stockholders' equity		2,119,563			2,833,620
Total liabilities and stockholders' equity	$	3,491,225		$	4,439,615

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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited, in thousands, except per share data)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2020			2019			2020			2019
Operating revenues:
Contract drilling	$	115,054		$	317,035		$	553,552		$	1,037,565
Pressure pumping		71,973			208,637			256,613			707,246
Directional drilling		10,271			47,037			56,498			150,214
Other		9,843			25,743			36,785			83,363
Total operating revenues		207,141			598,452			903,448			1,978,388
Operating costs and expenses:
Contract drilling		59,117			188,934			309,664			609,928
Pressure pumping		63,721			176,306			234,844			585,191
Directional drilling		9,754			56,215			54,348			143,919
Other		8,665			31,759			33,775			71,144
Depreciation, depletion, amortization and impairment		157,319			400,764			517,201			823,862
Impairment of goodwill		—			17,800			395,060			17,800
Selling, general and administrative		22,355			34,231			76,692			101,680
Credit loss expense		—			—			5,606			3,594
Restructuring expenses		—			—			38,338			—
Other operating expenses (income), net		776			(252	)		5,980			83
Total operating costs and expenses		321,707			905,757			1,671,508			2,357,201
Operating loss		(114,566	)		(307,305	)		(768,060	)		(378,813	)

Other income (expense):
Interest income		238			1,693			1,229			4,481
Interest expense, net of amount capitalized		(11,288	)		(20,739	)		(33,496	)		(47,021	)
Other		512			119			682			328
Total other expense		(10,538	)		(18,927	)		(31,585	)		(42,212	)

Loss before income taxes		(125,104	)		(326,232	)		(799,645	)		(421,025	)

Income tax benefit		(12,993	)		(64,513	)		(102,480	)		(81,245	)

Net loss	$	(112,111	)	$	(261,719	)	$	(697,165	)	$	(339,780	)

Net loss per common share:
Basic	$	(0.60	)	$	(1.31	)	$	(3.70	)	$	(1.65	)
Diluted	$	(0.60	)	$	(1.31	)	$	(3.70	)	$	(1.65	)

Weighted average number of common shares outstanding:
Basic		187,280			199,343			188,193			206,191
Diluted		187,280			199,343			188,193			206,191
Cash dividends per common share	$	0.02		$	0.04		$	0.08		$	0.12

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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(unaudited, in thousands)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2020			2019			2020			2019
Net loss	$	(112,111	)	$	(261,719	)	$	(697,165	)	$	(339,780	)
Other comprehensive income (loss), net of taxes of $0 for all periods:
Foreign currency translation adjustment		218			854			(473	)		2,646
Total comprehensive loss	$	(111,893	)	$	(260,865	)	$	(697,638	)	$	(337,134	)

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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

(unaudited, in thousands)

											Accumulated
	Common Stock				Additional						Other
	Number of				Paid-in			Retained			Comprehensive			Treasury
	Shares		Amount		Capital			Earnings			Income (Loss)			Stock			Total
Balance, December 31, 2019		269,372	$	2,694	$	2,875,680		$	1,294,902		$	5,478		$	(1,345,134	)	$	2,833,620
Net loss		—		—		—			(697,165	)		—			—			(697,165	)
Foreign currency translation adjustment		—		—		—			—			(473	)		—			(473	)
Vesting of restricted stock units		1,489		14		(14	)		—			—			—			—
Stock-based compensation		—		—		20,087			—			—			—			20,087
Payment of cash dividends		—		—		—			(15,110	)		—			—			(15,110	)
Dividend equivalents		—		—		—			(267	)		—			—			(267	)
Purchase of treasury stock		—		—		—			—			—			(21,129	)		(21,129	)
Balance, September 30, 2020		270,861	$	2,708	$	2,895,753		$	582,360		$	5,005		$	(1,366,263	)	$	2,119,563

												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

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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited, in thousands)

	Nine Months Ended
	September 30,
	2020			2019
Cash flows from operating activities:
Net loss	$	(697,165	)	$	(339,780	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, amortization and impairment		517,201			823,862
Impairment of goodwill		395,060			17,800
Dry holes and abandonments		1,256			94
Deferred income tax benefit		(100,212	)		(79,498	)
Stock-based compensation expense		20,087			30,058
Net gain on asset disposals		(3,357	)		(11,153	)
Net gain on insurance reimbursement		(4,172	)		—
Writedown of capacity reservation contract		9,207			12,673
Credit loss expense		5,606			3,594
Restructuring expenses, non-cash		24,068			—
Amortization of debt discount and issuance costs		673			668
Loss on early debt extinguishment		—			8,247
Changes in operating assets and liabilities:
Accounts receivable		202,733			144,210
Income taxes receivable/payable		1,285			(2,754	)
Inventory and other assets		22,250			42,092
Accounts payable		(57,788	)		(44,270	)
Accrued liabilities		(44,607	)		(16,993	)
Other liabilities		(8,840	)		(5,009	)
Net cash provided by operating activities		283,285			583,841
Cash flows from investing activities:
Purchases of property and equipment		(135,043	)		(283,288	)
Proceeds from disposal of assets and insurance claims		17,792			32,434
Other		(121	)		(13	)
Net cash used in investing activities		(117,372	)		(250,867	)
Cash flows from financing activities:
Purchases of treasury stock		(21,129	)		(230,275	)
Dividends paid		(15,110	)		(24,690	)
Debt issuance costs		(145	)		(150	)
Proceeds from long-term debt		—			150,000
Repayment of long-term debt		—			(308,061	)
Net cash used in financing activities		(36,384	)		(413,176	)
Effect of foreign exchange rate changes on cash		27			2
Net increase in cash and cash equivalents		129,556			(80,200	)
Cash and cash equivalents at beginning of period		174,185			245,029
Cash and cash equivalents at end of period	$	303,741		$	164,829

Supplemental disclosure of cash flow information:
Net cash (paid) received during the period for:
Interest, net of capitalized interest of $425 in 2020 and $548 in 2019	$	(32,605	)	$	(43,281	)
Income taxes		3,550			(861	)
Non-cash investing and financing activities:
Net decrease in payables for purchases of property and equipment	$	(38,312	)	$	(35,941	)
Net decrease in deposits on equipment purchases		3,338			4,787
Cashless exercise of stock options		—			9,219

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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Basis of Presentation

Basis of presentation – The unaudited interim condensed consolidated financial statements include the accounts of Patterson-UTI Energy, Inc. and its wholly-owned subsidiaries (collectively referred to herein as “we,” “us,” “our,” “ours” and like terms). All significant intercompany accounts and transactions have been eliminated. Except for wholly-owned subsidiaries, we have no controlling financial interests in any other entity which would require consolidation. As used in these notes, “we,” “us,” “our,” “ours” and like terms refer 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 us 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 we believe 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, 2019, as presented herein, was derived from our audited consolidated balance sheet 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 our Annual Report on Form 10-K for the fiscal year ended December 31, 2019. The results of operations for the three months and nine months ended September 30, 2020 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 our operations except for our 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 February 2016, the Financial Accounting Standards Board (“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 we are the lessor. For operating leases as a lessor, the minimum lease payments received are recognized as lease income on a straight-line basis over the lease term and the leased asset continues to be accounted for in accordance with Topic 360 within property and equipment, net in the condensed consolidated balance sheet. We adopted this new leasing guidance effective January 1, 2019.

In June 2016, the FASB issued an accounting standards update on measurement of credit losses on financial instruments. The new guidance requires us to measure all expected credit losses for financial instruments held at the reporting date based on historical experience, current conditions and reasonable and supportable forecasts. The new standard is effective for fiscal years beginning after December 15, 2019, including all interim periods within those years. We adopted ASU 2016-13 as of January 1, 2020. The adoption of this guidance and recognition of a loss allowance at an amount equal to expected credit losses for accounts receivable was not material and did not result in a transition adjustment to retained earnings. For more information regarding credit losses, see Note 2.

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. We adopted this new guidance on January 1, 2020 prospectively with respect to all implementation costs incurred after the date of adoption. There was no material impact on our 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. We adopted this new guidance on January 1, 2020 and there was no material impact on our consolidated financial statements.

Recently Issued Accounting Standards – In December 2019, the FASB issued an accounting standards update to simplify the accounting for income taxes. The amendments in the update are effective for public business entities for fiscal years beginning after December 15, 2020, with early adoption permitted. We plan to adopt this guidance on January 1, 2021 and are currently evaluating the impact of adoption on our consolidated financial statements.

In March 2020, the FASB issued an accounting standards update to provide temporary optional expedients that simplify the accounting for contract modifications to existing debt agreements expected to arise from the market transition from LIBOR to alternative reference rates. The amendments in the update are effective as of March 12, 2020 through December 31, 2022 and may be applied to contract modifications from the beginning of an interim period that includes or is subsequent to March 12, 2020. We plan to adopt this standard when LIBOR is discontinued and are currently evaluating the impact of adoption on our consolidated financial statements.

2. Credit Losses

ASC Topic 326 Current Expected Credit Losses (CECL)

On January 1, 2020, we adopted ASU 2016-13 Financial Instruments – Credit Losses (Topic 326) Measurement of Credit Losses on Financial Instruments, which introduces a new model to measure all expected credit losses for financial instruments held at the reporting date based on historical experience, current conditions and reasonable and supportable forecasts. Our customers are primarily oil and natural gas exploration and production companies, which are collectively exposed to oil and natural gas commodity price risk. Our customers require services from us at various stages of the exploration and production process. Accordingly, we have aggregated our trade receivables by segment. Any customers that have experienced a deterioration in credit quality are removed from the pool and evaluated individually. We utilized an accounts receivable aging schedule and historical credit loss information to estimate expected credit losses. Due to the significant decline in crude oil prices during the quarter ended March 31, 2020 and its related impact to our customers, we increased our historical credit loss rates used to determine our March 31, 2020 allowance for credit losses in the first quarter of 2020. We continued to monitor and evaluate our expected credit losses using these increased credit loss rates for the three months ended June 30, 2020 and September 30, 2020.

The adoption of the new accounting standard did not have a material impact on our consolidated financial statements and did not result in a transition adjustment to retained earnings.

The allowance for credit losses related to accounts receivable as of September 30, 2020, and changes for the quarters ended March 31, June 30 and September 30, 2020 are as follows (in thousands):

Balance at December 31, 2019	$	6,516
Provision for expected credit losses		1,055
Balance at March 31, 2020		7,571
Provision for expected credit losses		4,551
Balance at June 30, 2020		12,122
Provision for expected credit losses		—
Write-offs		(1,126	)
Balance at September 30, 2020		10,996

3. Revenues

ASC Topic 606 Revenue from Contracts with Customers

Our contracts with customers include both long-term and short-term contracts. Services that primarily generate our earned revenue include the operating business segments of contract drilling, pressure pumping and directional drilling, which comprise our reportable segments. We also derive revenues from our other operations, which include our operating business segments of oilfield rentals, equipment servicing, electrical controls and automation, and oil and natural gas working interests. For more information on our business segments, including disaggregated revenue recognized from contracts with customers, see Note 14.

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, we are 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 we expect to be entitled in exchange for transferring promised goods or services to a customer, based on terms of our contracts with our 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 us 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, we recognize 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, we will evaluate our 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.

We are a non-operating, working interest owner of oil and natural gas properties primarily located in Texas and New Mexico. The ownership terms are outlined in joint operating agreements for each well between the operator of the well and the various interest owners, including us, who are considered non-operators of the well. We receive revenue each period for our 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 our customers are recorded as revenue when incurred. The related costs are recorded as operating expenses when incurred.

Operating Lease Revenue – Lease income from equipment that we lease to others is recognized on a straight-line basis over the lease term.

Our disaggregated revenue recognized from contracts with customers is included in Note 14.

Accounts Receivable and Contract Liabilities

Accounts receivable is our right to consideration once it becomes unconditional. Payment terms typically range from 30 to 60 days.

Accounts receivable balances were $129 million and $336 million as of September 30, 2020 and December 31, 2019, respectively. These balances do not include amounts related to our 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.

We do 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, 2020 and 2019, approximately $0.1 million and $0.9 million, respectively, was amortized and recorded in drilling revenue.

Total contract liability balances were $0.6 million and $2.7 million as of September 30, 2020 and December 31, 2019, 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 rigs 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. Inventory

Inventory consisted of the following at September 30, 2020 and December 31, 2019 (in thousands):


	September 30, 2020		December 31, 2019
Finished goods	$	520	$	105
Work-in-process		1,262		1,229
Raw materials and supplies		31,911		35,023
Inventory	$	33,693	$	36,357

5. Property and Equipment

Property and equipment consisted of the following at September 30, 2020 and December 31, 2019 (in thousands):

	September 30, 2020			December 31, 2019
Equipment	$	7,858,967		$	8,114,326
Oil and natural gas properties		220,534			226,646
Buildings		195,494			184,700
Land		24,220			25,747
Total property and equipment		8,299,215			8,551,419
Less accumulated depreciation, depletion and impairment		(5,406,043	)		(5,244,742	)
Property and equipment, net	$	2,893,172		$	3,306,677

On a periodic basis, we evaluate our 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 our other marketed rigs are transferred to other rigs or to our yards to be used as spare equipment. The remaining components of these rigs are retired. In the second quarter of 2020, we recorded an impairment of $8.3 million related to the closing of our Canadian drilling operations.

We review our 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. We estimate future cash flows over the life of the respective assets or asset groupings in our assessment of impairment. These estimates of cash flows are based on historical cyclical trends in the industry as well as our 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.

2020 Triggering Event Assessment

Due to the decline in the market price of our common stock and commodity prices in the first quarter of 2020, we lowered our expectations with respect to future activity levels in certain of our operating segments. We deemed it necessary to assess the recoverability of our contract drilling, pressure pumping, directional drilling and oilfield rentals asset groups as of March 31, 2020. We performed an analysis as required by ASC 360-10-35 to assess the recoverability of the asset groups within our contract drilling, pressure pumping, directional drilling and oilfield rentals operating segments as of March 31, 2020. With respect to these asset groups, future cash flows were estimated over the expected remaining life of the assets, and we 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 15%, 22%, 3% and 9%, respectively.

For the assessment performed as of March 31, 2020, the expected cash flows for our asset groups included assumptions about utilization, revenue and costs for our equipment and services that were estimated based upon our 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 second half of 2019 and the first quarter of 2020 and would begin to recover in 2022 in response to improved oil prices. While we believe these assumptions with respect to future oil pricing are reasonable, actual future prices and activity levels may vary significantly from the ones that were assumed. The timeframe over which oil prices and activity levels may recover is highly uncertain.

All of these factors are beyond our control. If the lower oil price environment experienced in 2020 were to last into late 2022 and beyond, our 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 charges could be material.

We have concluded that no triggering events occurred during the three months ended June 30, 2020 and September 30, 2020 with respect to our asset groups based on our recent results of operations, our expectations of operating results in future periods and prevailing commodity prices at the time.

6. Goodwill and Intangible Assets

Goodwill — Goodwill by operating segment as of September 30, 2020 and changes for the nine months then ended are as follows (in thousands):

	Contract
	Drilling
Balance at beginning of period	$	395,060
Impairment		(395,060	)
Balance at end of period	$	—

There were no accumulated impairment losses related to goodwill in the contract drilling segment as of December 31, 2019.

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. Our reporting units for impairment testing are our operating segments. We determine 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, we 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 our common stock and commodity prices in the first quarter of 2020, we lowered our expectations with respect to future activity levels in our contract drilling reporting unit. We performed a quantitative impairment assessment of our goodwill as of March 31, 2020. In completing the assessment, the fair value of our contract drilling operating segment was estimated using the income approach. The estimate of fair value 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 our contract drilling reporting unit, such as future oil and natural gas prices and projected demand for our services, and assumptions related to discount rate and long-term growth rate.

Based on the results of the goodwill impairment test as of March 31, 2020, impairment was indicated in our contract drilling reporting unit. We recognized an impairment charge of $395 million in the quarter ended March 31, 2020 associated with the impairment of all of the goodwill in our contract drilling reporting unit.

Intangible Assets — The following table presents the gross carrying amount and accumulated amortization of our intangible assets as of September 30, 2020 and December 31, 2019 (in thousands):

	September 30, 2020							December 31, 2019
	Gross					Net		Gross					Net
	Carrying		Accumulated			Carrying		Carrying		Accumulated			Carrying
	Amount		Amortization			Amount		Amount		Amortization			Amount
Customer relationships	$	28,000	$	(26,453	)	$	1,547	$	28,000	$	(19,710	)	$	8,290
Developed technology		55,772		(24,484	)		31,288		55,772		(15,386	)		40,386
Internal use software		603		(287	)		316		482		(214	)		268
	$	84,375	$	(51,224	)	$	33,151	$	84,254	$	(35,310	)	$	48,944

Amortization expense on intangible assets of approximately $5.3 million was recorded in each three month period ended September 30, 2020 and 2019, respectively. Amortization expense on intangible assets of approximately $15.9 million and $12.6 million was recorded in the nine months ended September 30, 2020 and 2019, respectively.

7. Accrued Liabilities

Accrued liabilities consisted of the following at September 30, 2020 and December 31, 2019 (in thousands):


	September 30, 2020		December 31, 2019
Salaries, wages, payroll taxes and benefits	$	29,058	$	57,615
Workers' compensation liability		73,357		81,112
Property, sales, use and other taxes		25,400		22,404
Insurance, other than workers' compensation		7,924		9,218
Accrued interest payable		11,650		12,021
Accrued restructuring expenses		6,311		—
Other		27,860		37,480
Accrued liabilities	$	181,560	$	219,850

8. Long Term Debt

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. We repaid $50 million of the borrowings under the Term Loan Agreement on December 16, 2019.

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, 2020, the applicable margin on LIBOR rate loans and base rate loans was 1.375% and 0.375%, 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 the ability of each of our subsidiaries to incur debt and grant liens. If our credit rating is below investment grade at both Moody’s and S&P, 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. Restricted payments include, among other things, dividend payments, repurchases of our common stock, distributions to holders of our common stock or any other payment or other distribution to third parties on account of our or our subsidiaries’ equity interests. Our credit rating is currently investment grade at one of the two ratings agencies.

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 at both Moody’s and S&P. Our credit rating is currently investment grade at one of the two ratings agencies. 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. We were in compliance with these covenants at September 30, 2020.

As of September 30, 2020, we had $100 million in borrowings outstanding under the Term Loan Agreement at a LIBOR interest rate of 1.52%.

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, 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. On March 27, 2020, we entered into Amendment No. 2 to Amended and Restated Credit Agreement (“Amendment No. 2”) to, among other things, extend the maturity date for $550 million of revolving credit commitments of certain lenders under the Credit Agreement from March 27, 2024 to March 27, 2025. We have the option, subject to certain conditions, to exercise one additional one-year extension 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 the ability of each of our subsidiaries to incur debt and grant liens. If our credit rating is below investment grade at both Moody’s and S&P, 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. Restricted payments include, among other things, dividend payments, repurchases of our common stock, distributions to holders of our common stock or any other payment or other distribution to third parties on account of our or our subsidiaries’ equity interests. Our credit rating is currently investment grade at one of the two ratings agencies. 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. We were in compliance with these covenants at September 30, 2020.

As of September 30, 2020, we had no borrowings outstanding under our revolving credit facility. We had $0.1 million in letters of credit outstanding under the Credit Agreement at September 30, 2020 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, 2020, we had $60.7 million in letters of credit outstanding under the Reimbursement Agreement.

Under the terms of the Reimbursement Agreement, we will reimburse Scotiabank on demand for any amounts that Scotiabank has disbursed under any letters of credit. Fees, charges and other reasonable expenses for the issuance of letters of credit are payable by us at the time of issuance at such rates and amounts as are in accordance with Scotiabank’s prevailing practice. We are obligated to pay to Scotiabank interest on all amounts not paid by us 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 or 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, our payment obligations under the Reimbursement Agreement are jointly and severally guaranteed as to payment and not as to collection by our subsidiaries that from time to time guarantee payment under the Credit Agreement. None of our subsidiaries are currently required to guarantee payment under the Credit Agreement.

Series A Senior Notes and Series B Senior Notes— On October 5, 2010, we completed the issuance and sale of $300 million in aggregate principal amount of our 4.97% Series A Senior Notes due October 5, 2020 (the “Series A Notes”) in a private placement. The Series A Notes 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.

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 bore interest at a rate of 4.27% per annum. On December 16, 2019, we fully prepaid the Series B Notes. The total amount of the prepayment, including the applicable “make-whole” premium, was approximately $315 million, which represents 100% of the principal and the “make-whole” premium to the prepayment date.

2028 Senior Notes and 2029 Senior Notes – On January 19, 2018, we completed our offering of $525 million in 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. On November 15, 2019, we completed an offering of $350 million in aggregate principal amount of our 5.15% Senior Notes due 2029 (the “2029 Notes”). The net proceeds before offering expenses were approximately $347 million. We used a portion of the net proceeds from the offering to prepay our Series B Notes. The remaining net proceeds and available cash on hand was used to repay $50 million of the borrowings under the Term Loan Agreement.

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.

We pay interest on the 2029 Notes on May 15 and November 15 of each year. The 2029 Notes will mature on November 15, 2029. The 2029 Notes bear interest at a rate of 5.15% per annum.

The 2028 Notes and 2029 Notes (together, the “Senior Notes”) are our 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 Senior 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 Senior Notes will be structurally subordinated to the liabilities (including trade payables) of our subsidiaries that do not guarantee the Senior Notes. None of our subsidiaries are currently required to be a guarantor under the Senior Notes. If our subsidiaries guarantee the Senior Notes in the future, such guarantees (the “Guarantees”) will rank equally in right of payment with all of the guarantors’ future unsecured senior debt and senior in right of payment to all of the guarantors’ future subordinated debt. The Guarantees will be effectively subordinated to any of the guarantors’ future secured debt to the extent of the value of the assets securing such debt.

We, at our option, may redeem the Senior 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 Senior Notes to be redeemed, plus accrued and unpaid interest, if any, on those Senior Notes to the redemption date, plus a “make-whole” premium. Additionally, commencing on November 1, 2027, in the case of the 2028 Notes, and on August 15, 2029, in the case of the 2029 Notes, we, at our option, may redeem the respective Senior Notes in whole or in part, at a redemption price equal to 100% of the principal amount of the Senior Notes to be redeemed, plus accrued and unpaid interest, if any, on those Senior Notes to the redemption date.

The indentures pursuant to which the Senior Notes were issued include 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 indentures.

Upon the occurrence of a change of control triggering event, as defined in the indentures, each holder of the Senior Notes may require us to purchase all or a portion of such holder’s Senior 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 indentures also provide 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 Senior Notes to become or to be declared due and payable.

Debt issuance costs – We incurred approximately $0.4 million debt issuance costs in connection with our entry into Amendment No. 2. These costs were deferred and are being recognized as interest expense over the term of the underlying debt. Debt issuance costs, except those related to line-of-credit arrangements, are presented in the balance sheet as a direct deduction from the carrying amount of the related debt. Debt issuance costs related to line-of-credit arrangements are classified as a deferred charge. Amortization of debt issuance costs is reported as interest expense.

Interest expense related to the amortization of debt issuance costs was approximately $0.3 million and $0.5 million for the three months ended September 30, 2020 and 2019, respectively and $0.8 million and $1.2 million for the nine months ended September 30, 2020 and 2019, respectively.

Presented below is a schedule of the principal repayment requirements of long-term debt as of September 30, 2020 (in thousands):

Year ending December 31,
2020	$	—
2021		—
2022		100,000
2023		—
2024		—
Thereafter		875,000
Total	$	975,000

9. Commitments and Contingencies

As of September 30, 2020, we maintained letters of credit in the aggregate amount of $60.8 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, 2020, no amounts had been drawn under the letters of credit.

As of September 30, 2020, we had commitments to purchase major equipment and make investments totaling approximately $11.0 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 2020 through 2022. As of September 30, 2020, the remaining minimum obligation under these agreements was approximately $24.9 million, of which approximately $11.5 million, $10.0 million, and $3.4 million relate to the remainder of 2020, 2021, and 2022, respectively. In 2017, we entered into a capacity reservation agreement that required a cash deposit to increase access to finer grades of sand for our pressure pumping business. As market prices for sand have substantially decreased since 2017, we have purchased lower cost sand outside of this capacity reservation contract and recorded charges of $9.2 million and $12.7 million in the second quarters of 2020 and 2019, respectively, to revalue the deposit to its expected realizable value. The deposit related to the capacity reservation agreement has no balance remaining subsequent to the charge recorded in the second quarter of 2020.

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 or results of operations.

10. Stockholders’ Equity

Stockholder Rights Agreement — On April 22, 2020, our Board of Directors adopted a stockholder rights agreement and declared a dividend of one right (a “Right”) for each outstanding share of our common stock to stockholders of record at the close of business on May 8, 2020. Each Right entitles its holder, subject to the terms of the Rights Agreement (as defined below), to purchase from us one one-thousandth of a share of our Series A Junior Participating Preferred Stock, par value $0.01 per share, at an exercise price of $17.00 per Right, subject to adjustment. The description and terms of the Rights are set forth in a stockholder rights agreement, dated as of April 22, 2020 (the “Rights Agreement”), between us and Continental Stock Transfer & Trust Company, as rights agent (the “Rights Agent”).

Initially, these Rights are not exercisable and trade with our shares of common stock. Under the Rights Agreement, the Rights generally become exercisable only if a person or group of persons acting together (each, an “acquiring person”) acquires beneficial ownership of 10% (12% for passive investors) or more of the outstanding shares of our common stock.

In that situation, each holder of a Right (other than the acquiring person, whose Rights will become void) will become entitled to purchase additional shares of our common stock at a 50% discount. In addition, if we are acquired in a merger or other business combination after an unapproved party acquires more than 10% (12% for passive investors) of our outstanding shares of common stock, each holder of a Right would then be entitled to purchase shares of the acquiring company’s stock at a 50% discount. Our Board of Directors, at its option, may exchange each Right (other than Rights owned by the acquiring person that have become void) in whole or in part, at an exchange ratio of one share of our common stock per outstanding Right, subject to adjustment. Except as provided in the Rights Agreement, our Board of Directors is entitled to redeem the Rights at $0.001 per Right.

Persons or groups that beneficially own 10% (12% for passive investors) or more of our outstanding common stock prior to our announcement of our adoption of the Rights Agreement will generally not cause the Rights to be exercisable until such time as those persons or groups become the beneficial owner of any additional shares of our common stock, subject to certain exceptions.

On July 22, 2020, we and the Rights Agent entered into an amendment to the Rights Agreement. The amendment revises the definition of “acquiring person” in the Rights Agreement to exclude Excluded Persons. The amendment defines “Excluded Persons” as BlackRock, Inc. (collectively with the investment funds and accounts for which it acts or may act as manager and/or investment advisor, “BlackRock”) and The Vanguard Group, Inc. (together with the investment funds and accounts for which it acts or may act as manager and/or investment advisor, “Vanguard”). Our Board of Directors may determine, in its sole discretion, that BlackRock or Vanguard is no longer an “Excluded Person” if any of the representations, warranties, conditions or provisions in letter agreements between us and BlackRock or Vanguard, respectively, are breached or cease to be true, correct and complete in all material respects. Under each letter agreement, BlackRock and Vanguard represent, respectively, among other things, that:

•

Such investor will not acquire 20% or more of our then-outstanding common stock;

•

No single fund of such investor holds or will hold an economic interest (taking into account the ownership rules of Section 382 of the Internal Revenue Code) of 4.9% or more of our common stock, other than as disclosed to us; and

•

Such investor will only acquire beneficial ownership of our common stock in the ordinary course of business and not with the purpose or effect of changing or influencing control of us.

The Rights Agreement will expire on April 21, 2021, but our Board of Directors may consider earlier termination of the Rights Agreement if warranted.

Cash Dividends — We paid cash dividends during the nine months ended September 30, 2020 and 2019 as follows:

2020:	Per Share		Total
			(in thousands)
Paid on March 19, 2020	$	0.04	$	7,629
Paid on June 18, 2020		0.02	$	3,735
Paid on September 17, 2020		0.02	$	3,746
Total cash dividends	$	0.08	$	15,110

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

On October 21, 2020, our Board of Directors approved a cash dividend on our common stock in the amount of $0.02 per share to be paid on December 17, 2020 to holders of record as of December 3, 2020. 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.

Share Repurchases and Acquisitions — 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. There is no expiration date associated with the buyback program. As of September 30, 2020, we had remaining authorization to purchase approximately $130 million of our outstanding common stock under the stock buyback program. Shares of stock purchased under the buyback program are held as treasury shares.

We acquired shares of stock from employees during 2020 that are accounted for as treasury stock. These shares were acquired to satisfy 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 (the “2014 Plan”), as amended, and not pursuant to the stock buyback program.

Treasury stock acquisitions during the nine months ended September 30, 2020 were as follows (dollars in thousands):

	Shares		Cost
Treasury shares at beginning of period		77,336,387	$	1,345,134
Purchases pursuant to stock buyback program		5,826,266		20,000
Acquisitions pursuant to long-term incentive plan		222,550		1,129
Treasury shares at end of period		83,385,203	$	1,366,263

The reconciliation of changes in stockholders’ equity for the periods ended September 30, 2020 and 2019, are presented as follows (in thousands):

	For the nine months ended September 30, 2020
											Accumulated
	Common Stock				Additional						Other
	Number of				Paid-in			Retained			Comprehensive			Treasury
	Shares		Amount		Capital			Earnings			Income (Loss)			Stock			Total
Balance, December 31, 2019		269,372	$	2,694	$	2,875,680		$	1,294,902		$	5,478		$	(1,345,134	)	$	2,833,620
Net loss		—		—		—			(434,722	)		—			—			(434,722	)
Foreign currency translation adjustment		—		—		—			—			(1,386	)		—			(1,386	)
Vesting of restricted stock units		151		1		(1	)		—			—			—			—
Stock-based compensation		—		—		9,160			—			—			—			9,160
Payment of cash dividends		—		—		—			(7,629	)		—			—			(7,629	)
Dividend equivalents		—		—		—			(125	)		—			—			(125	)
Purchase of treasury stock		—		—		—			—			—			(20,025	)		(20,025	)
Balance, March 31, 2020		269,523	$	2,695	$	2,884,839		$	852,426		$	4,092		$	(1,365,159	)	$	2,378,893
Net loss		—		—		—			(150,332	)		—			—			(150,332	)
Foreign currency translation adjustment		—		—		—			—			695			—			695
Vesting of restricted stock units		1,046		11		(11	)		—			—			—			—
Stock-based compensation		—		—		4,335			—			—			—			4,335
Payment of cash dividends		—		—		—			(3,735	)		—			—			(3,735	)
Dividend equivalents		—		—		—			(73	)		—			—			(73	)
Purchase of treasury stock		—		—		—			—			—			(910	)		(910	)
Balance, June 30, 2020		270,569	$	2,706	$	2,889,163		$	698,286		$	4,787		$	(1,366,069	)	$	2,228,873
Net loss		—		—		—			(112,111	)		—			—			(112,111	)
Foreign currency translation adjustment		—		—		—			—			218			—			218
Vesting of restricted stock units		292		2		(2	)		—			—			—			—
Stock-based compensation		—		—		6,592			—			—			—			6,592
Payment of cash dividends		—		—		—			(3,746	)		—			—			(3,746	)
Dividend equivalents		—		—		—			(69	)		—			—			(69	)
Purchase of treasury stock		—		—		—			—			—			(194	)		(194	)
Balance, September 30, 2020		270,861	$	2,708	$	2,895,753		$	582,360		$	5,005		$	(1,366,263	)	$	2,119,563

	For the nine months ended September 30, 2019
												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		—			—		—			(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

11. Stock-based Compensation

We use share-based payments to compensate employees and non-employee directors. We recognize 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. Our share-based awards also include share-settled performance unit awards. Share-settled performance unit awards are accounted for as equity awards. In 2020, we granted performance-based cash-settled phantom units, which are accounted for as a liability classified award. We issue 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 — We estimate the grant date fair values of stock options using the Black-Scholes-Merton valuation model. Volatility assumptions are based on the historic volatility of our 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 our 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, 2020 or 2019.

Stock option activity from January 1, 2020 to September 30, 2020 follows:

				Weighted
				Average
	Underlying			Exercise Price
	Shares			Per Share
Outstanding at January 1, 2020		4,766,150		$	20.62
Exercised		—		$	—
Expired		(710,000	)	$	14.83
Outstanding at September 30, 2020		4,056,150		$	21.63
Exercisable at September 30, 2020		4,041,150		$	21.64

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

Restricted stock activity from January 1, 2020 to September 30, 2020 follows:

				Weighted
				Average Grant
				Date Fair Value
	Shares			Per Share
Non-vested restricted stock outstanding at January 1, 2020		72,051		$	21.59
Vested		(72,051	)	$	21.59
Forfeited		—		$	—
Non-vested restricted stock outstanding at September 30, 2020		—		$	—

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. We use the straight-line method to recognize periodic compensation cost over the vesting period.

Restricted stock unit activity from January 1, 2020 to September 30, 2020 follows:

							Weighted
							Average Grant
	Time			Performance			Date Fair Value
	Based			Based			Per Share
Non-vested restricted stock units outstanding at January 1, 2020		2,631,726			397,315		$	15.81
Granted		1,691,246			—		$	4.25
Vested		(1,118,260	)		(38,000	)	$	16.18
Forfeited		(272,148	)		—		$	13.79
Non-vested restricted stock units outstanding at September 30, 2020		2,932,564			359,315		$	9.91

Performance Unit Awards — We have 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 our 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 April 2018, the recipients will receive a target number of shares if our total shareholder return during the performance period, when compared to the peer group, is at the 50th percentile. For the Performance Units granted in April 2019 and April 2020, the recipients will receive the target number of shares if our total shareholder return during the performance period, when compared to the peer group, is at the 55th percentile. If our total shareholder return during the performance period, when compared to the peer group, is at the 75th percentile or higher, then the recipients will receive two times the target number of shares. If our total shareholder return during the performance period, when compared to the peer group, is at the 25th percentile, then the recipients will only receive one-half of the target number of shares. If our total shareholder return during the performance period, when compared to the peer group, is between the 25th and target percentile, or the target and 75th percentile, then the shares to be received by the recipients will be determined using linear interpolation for levels of achievement between these points. For the Performance Units granted in 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 and April 2020, the payout shall not exceed the target number of shares if our total shareholder return is negative or zero. Additionally, the Performance Units granted in April 2020 will not pay out if our total shareholder return is not equal to or greater than the total stockholder return of the S&P 500 Index for the Performance Period.

In May 2020, 332,773 shares were issued to settle the 2017 Performance Units. The Performance Units granted in 2018, 2019 and 2020 have not reached the end of their respective performance periods.

The total target number of shares with respect to the Performance Units for the awards granted in 2016-2020 is set forth below:

	2020		2019		2018		2017		2016
	Performance		Performance		Performance		Performance		Performance
	Unit Awards		Unit Awards		Unit Awards		Unit Awards		Unit Awards
Target number of shares		500,500		489,800		310,700		186,198		185,000

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):

	2020		2019		2018		2017		2016
	Performance		Performance		Performance		Performance		Performance
	Unit Awards		Unit Awards		Unit Awards		Unit Awards		Unit Awards
Fair value at date of grant	$	826	$	9,958	$	8,004	$	5,780	$	3,854

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):

	2020		2019		2018		2017		2016
	Performance		Performance		Performance		Performance		Performance
	Unit Awards		Unit Awards		Unit Awards		Unit Awards		Unit Awards
Three months ended September 30, 2020	$	69	$	830	$	667	$	—	$	—
Three months ended September 30, 2019	$	—	$	830	$	667	$	482	$	—
Nine months ended September 30, 2020	$	138	$	2,489	$	2,001	$	642	$	—
Nine months ended September 30, 2019	$	—	$	1,660	$	2,001	$	1,445	$	321

Phantom Units — In May 2020, the Compensation Committee approved a grant of long-term performance-based phantom units to our Chief Executive Officer and President, William A. Hendricks, Jr (the “Phantom Units”). The Phantom Units were granted outside of the 2014 Plan. Pursuant to this phantom unit grant, Mr. Hendricks may earn from 0% to 200% of a target award of 298,500 phantom units based on our achievement of the same performance conditions over the same Performance Period that applies to the Performance Units granted in April 2020, as described above. Earned Phantom Units, if any, will be settled in 2023, following completion of the three-year Performance Period, in a cash payment equal to the number of earned phantom units multiplied by our average trading price per share over the twenty consecutive trading days ending March 31, 2023. Because the Phantom Units are cash-settled awards, they are accounted for as a liability classified award. The grant date fair value of the Phantom Units was $1.2 million. Compensation expense is recognized on a straight-line basis over the performance period, with the amount recognized fluctuating as a result of the Phantom Units being remeasured to fair value at the end of each reporting period due to their liability-award classification. We recognized minimal expense for the three months ended September 30, 2020 and $0.2 million for the nine months ended September 30, 2020.

12. 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, 2020 was 10.4%, compared with 19.8% for the three months ended September 30, 2019. The lower effective income tax rate for the three months ended September 30, 2020 was primarily attributable to the non-deductible portion of the goodwill impairment recorded in the first quarter of 2020.

Our effective income tax rate for the nine months ended September 30, 2020 was 12.8%, compared with 19.3% for the nine months ended September 30, 2019. The lower effective income tax rate for the nine months ended September 30, 2020 was primarily attributable to the non-deductible portion of the goodwill impairment recorded in the first quarter of 2020.

We continue to monitor income tax developments in the United States and other countries where we operate. During the first quarter of 2020, the United States enacted legislation related to COVID-19, which includes tax provisions. We have considered these tax provisions and do not currently expect any material impact to our financial statements. We will incorporate into our future financial statements the impacts, if any, of future regulations and additional authoritative guidance when finalized.

13. Earnings Per Share

We provide a dual presentation of our net loss per common share in our unaudited condensed consolidated statements of operations: basic net loss per common share (“Basic EPS”) and diluted net loss per common share (“Diluted EPS”).

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

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

The following table presents information necessary to calculate net loss per share for the three and nine months ended September 30, 2020 and 2019 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,
	2020			2019			2020			2019
BASIC EPS:
Net loss attributed to common stockholders	$	(112,111	)	$	(261,719	)	$	(697,165	)	$	(339,780	)
Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock		187,280			199,343			188,193			206,191
Basic net loss per common share	$	(0.60	)	$	(1.31	)	$	(3.70	)	$	(1.65	)
DILUTED EPS:
Net loss attributed to common stockholders	$	(112,111	)	$	(261,719	)	$	(697,165	)	$	(339,780	)
Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock		187,280			199,343			188,193			206,191
Add dilutive effect of potential common shares		—			—			—			—
Weighted average number of diluted common shares outstanding		187,280			199,343			188,193			206,191
Diluted net loss per common share	$	(0.60	)	$	(1.31	)	$	(3.70	)	$	(1.65	)
Potentially dilutive securities excluded as anti-dilutive		8,490			9,753			8,490			9,753

14. Business Segments

At September 30, 2020, we 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 our chief operating decision maker. The results of operations in these segments are regularly reviewed by the chief operating decision maker for purposes of determining resource allocation and assessing performance.

The following tables summarize selected financial information relating to our business segments (in thousands):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2020			2019			2020			2019
Revenues:
Contract drilling	$	115,105		$	317,468		$	554,421		$	1,038,705
Pressure pumping		71,973			208,637			256,613			707,246
Directional drilling		10,271			47,037			56,498			150,214
Other operations ⁽¹⁾		11,756			32,809			46,061			96,052
Elimination of intercompany revenues ⁽²⁾		(1,964	)		(7,499	)		(10,145	)		(13,829	)
Total revenues	$	207,141		$	598,452		$	903,448		$	1,978,388
Income (loss) before income taxes:
Contract drilling	$	(47,214	)	$	(169,528	)	$	(481,974	)	$	(131,817	)
Pressure pumping		(30,856	)		(42,962	)		(134,896	)		(76,138	)
Directional drilling		(9,912	)		(32,501	)		(34,892	)		(43,458	)
Other operations		(6,421	)		(39,192	)		(35,547	)		(51,713	)
Corporate		(20,163	)		(23,122	)		(75,145	)		(72,093	)
Credit loss expense		—			—			(5,606	)		(3,594	)
Interest income		238			1,693			1,229			4,481
Interest expense		(11,288	)		(20,739	)		(33,496	)		(47,021	)
Other		512			119			682			328
Loss before income taxes	$	(125,104	)	$	(326,232	)	$	(799,645	)	$	(421,025	)
Depreciation, depletion, amortization and impairment:
Contract drilling	$	102,275		$	296,119		$	328,843		$	554,838
Pressure pumping		37,104			72,139			118,586			188,459
Directional drilling		9,600			20,518			29,698			41,755
Other operations		6,852			10,227			35,087			33,472
Corporate		1,488			1,761			4,987			5,338
Total depreciation, depletion, amortization and impairment	$	157,319		$	400,764		$	517,201		$	823,862
Capital expenditures:
Contract drilling	$	9,502		$	34,752		$	101,448		$	158,141
Pressure pumping		1,653			19,826			17,880			90,028
Directional drilling		510			5,559			4,562			11,121
Other operations		1,704			7,191			9,776			21,194
Corporate		73			700			1,377			2,804
Total capital expenditures	$	13,442		$	68,028		$	135,043		$	283,288

	September 30, 2020		December 31, 2019
Identifiable assets:
Contract drilling	$	2,415,566	$	3,190,463
Pressure pumping		488,456		695,570
Directional drilling		111,192		164,273
Other operations		92,890		128,290
Corporate ⁽³⁾		383,121		261,019
Total assets	$	3,491,225	$	4,439,615

⁽¹⁾	Other operations includes our oilfield rentals business, drilling equipment service business, the electrical controls and automation business and the oil and natural gas working interests.

⁽²⁾

Intercompany revenues consist of revenues from contract drilling for services provided to our other operations, and revenues from other operations for services provided to contract drilling, pressure pumping and within other operations. These revenues are generally based on estimated external selling prices and are eliminated during consolidation.

⁽³⁾	Corporate assets primarily include cash on hand and certain property and equipment.

15. 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 our outstanding debt balances as of September 30, 2020 and December 31, 2019 is set forth below (in thousands):

	September 30, 2020				December 31, 2019
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
3.95% Senior Notes	$	525,000	$	404,665	$	525,000	$	511,485
5.15% Senior Notes		350,000		268,820		350,000		358,864
2019 Term Loan		100,000		100,000		100,000		100,000
Total debt	$	975,000	$	773,485	$	975,000	$	970,349

The fair values of the 3.95% Senior Notes at September 30, 2020 and December 31, 2019 are based on discounted cash flows associated with the notes using the 8.16% market rate of interest at September 30, 2020 and the 4.33% market rate of interest at December 31, 2019. The fair values of the 5.15% Senior Notes at September 30, 2020 and December 31, 2019 are based on discounted cash flows associated with the notes using the 8.91% market rate of interest at September 30, 2020 and the 4.81% market rate of interest at December 31, 2019. The fair value estimates of the 3.95% Senior Notes and the 5.15% Senior Notes are considered Level 1 fair value estimates in the fair value hierarchy of fair value accounting. The carrying values of the balance outstanding at September 30, 2020 under the Term Loan Agreement approximated its fair value as the instrument has a floating interest rate.

16. Restructuring Expenses

Contract termination costs relate primarily to agreements to purchase minimum quantities of proppants (sand) from certain vendors. These costs are primarily comprised of a $5.3 million negotiated settlement and termination of an existing contract to purchase minimum quantities of sand and $14.0 million of contractual future payments under two existing contracts to purchase minimum quantities of sand without future economic benefit to us. We will not receive any sand under these contracts. Other exit costs relate primarily to facility closure costs and moving expenses.

The right of use (“ROU”) asset abandonments relate to facility and equipment ROU assets abandoned as a result of restructuring.

The following table presents restructuring expenses by reportable segment for the nine months ended September 30, 2020 (in thousands):

	Contract Drilling		Pressure Pumping		Directional Drilling		Other Operations		Corporate		Total
Severance costs	$	1,821	$	3,460	$	503	$	501	$	215	$	6,500
Contract termination costs		—		20,373		—		—		—		20,373
Other exit costs		523		194		827		—		—		1,544
ROU asset abandonments		86		7,304		1,845		—		686		9,921
Total	$	2,430	$	31,331	$	3,175	$	501	$	901	$	38,338

The following table presents the consolidated balance sheet captions that restructuring accruals are included in as of September 30, 2020 (in thousands):

	September 30, 2020
Accrued liabilities	$	6,311
Other long-term liabilities		7,200
Total	$	13,511

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, “we,” “us,” our,” “ours” 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 those set forth under “Risk Factors” contained in Part II, Item 1A of this Report as well as, among others, risks and uncertainties relating to:

•

adverse oil and natural gas industry conditions, including the rapid decline in crude oil prices as a result of economic repercussions from the recent COVID-19 pandemic;

•

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, including the ability to develop and obtain satisfactory returns from new technology;

•

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, social and governance practices, including the perception thereof;

•

environmental risks and ability to satisfy future environmental costs;

•

legal proceedings and actions by governmental or other regulatory agencies;

•

technology-related disputes;

•

the ability to effectively identify and enter new markets;

•

weather;

•

operating costs;

•

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

•

ability to obtain insurance coverage on commercially reasonable terms;

•

financial flexibility;

•

interest rate volatility;

•

adverse credit and equity market conditions;

•

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

•

stock price volatility;

•

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, 2019 and may be contained in our future filings with the SEC. You are cautioned not to place undue reliance on any of our forward-looking statements. The forward-looking statements speak only as of the date made and, other than as required by law, we undertake no obligation to update publicly or revise any of these forward-looking statements, whether as a result of new information, future events or otherwise. In the event that we update any forward-looking statement, no inference should be made that we will make additional updates with respect to that statement, related matters or any other forward-looking statements. All subsequent written and oral forward-looking statements concerning us or other matters and attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements above.

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

Management Overview — We are a Houston, Texas-based oilfield services company that primarily owns and operates one of the largest fleets of land-based drilling rigs in the United States and a large fleet of pressure pumping equipment.

Our contract drilling business operates in the continental United States and, from time to time, we pursue contract drilling opportunities in other select markets. Our pressure pumping business operates primarily in Texas and the Appalachian region. 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 we 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.

Reduced demand for crude oil and refined products related to the COVID-19 pandemic, combined with production increases from OPEC+, has led to a significant reduction in crude oil prices and demand for drilling and completion services in North America.

Oil prices remain extremely volatile, as the closing price of oil (WTI-Cushing) reached a first quarter 2020 high of $63.27 per barrel on January 6, 2020, declined to negative $36.98 per barrel on April 20, 2020, and closed at $40.69 per barrel on October 19, 2020. In response to the rapid decline in commodity prices, E&P companies acted swiftly to reduce drilling and completion activity starting late in the first quarter.

Our average active rig count for the third quarter of 2020 was 60 rigs. This was a decrease from our average active rig count of 82 rigs for the second quarter of 2020. Our rig count stabilized during the third quarter and started to improve late in the quarter. We expect our average rig count for the fourth quarter will be 61 rigs. Based on contracts currently in place, we expect an average of 43 rigs operating under term contracts (contracts with a duration of six months or more) during the fourth quarter of 2020 and an average of 35 rigs operating under term contracts during the twelve months ending September 30, 2021.

Due to the downturn in completions activity since March, we averaged five active pressure pumping spreads during the third quarter, up from an average of four active spreads during the second quarter. For the fourth quarter, we expect to average six active spreads, but we expect lower utilization during the fourth quarter due to typical seasonality.

During the second quarter of 2020, we implemented a restructuring plan to improve operating margins, achieve operational efficiencies and reduce indirect support costs. The restructuring included workforce reductions, changes to management structure and facility consolidations and closures. We recorded $38.3 million of charges associated with this plan in the second quarter of 2020. There were no restructuring charges in the comparable period of 2019. We completed the restructuring plan during the third quarter of 2020 and did not incur additional expenses related to the plan. In particular with our pressure pumping business, we believe these restructuring changes are structural and will result in significant cost savings. The restructuring charges during the second quarter of 2020 consisted of the following, as further described in Note 16 of Notes to unaudited condensed consolidated financial statements:

The following table presents restructuring expenses by reportable segment for the nine months ended September 30, 2020 (in thousands):

	Contract Drilling		Pressure Pumping		Directional Drilling		Other Operations		Corporate		Total
Severance costs	$	1,821	$	3,460	$	503	$	501	$	215	$	6,500
Contract termination costs		—		20,373		—		—		—		20,373
Other exit costs		523		194		827		—		—		1,544
ROU asset abandonments		86		7,304		1,845		—		686		9,921
Total	$	2,430	$	31,331	$	3,175	$	501	$	901	$	38,338

In the second quarter of 2020, we estimated that the 2020 restructuring plan will result in annual cost savings of approximately $94 million, beginning in the third quarter of 2020. Of these estimated annual cost savings, approximately $14 million, $43 million, $7 million and $8 million are attributable to operating expense savings for contract drilling, pressure pumping, directional drilling and other operations, respectively. Annual selling, general and administrative cost savings are estimated to be approximately $22 million. Nothing has occurred as of September 30, 2020 that would cause a revision to this estimate.

Our revenues, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas and upon our customers’ ability to access capital to fund their operating and capital expenditures. 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, such as now, when oil and natural gas prices deteriorate or when our customers have a reduced ability to access capital, the demand for our services generally weakens, and we experience downward pressure on pricing for our services. We may also be impacted by delayed customer payments and payment defaults associated with customer liquidity issues and bankruptcies.

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.

In addition to the dependence on oil and natural gas prices and demand for our services, we are highly impacted by operational risks, competition, labor issues, weather, the availability, from time to time, 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, including as a result of the COVID-19 pandemic. Please see “Risk Factors” included in Part II, Item 1A of this Report and Item 1A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2019.

For the three and nine months ended September 30, 2020 and 2019, our operating revenues consisted of the following (dollars in thousands):

	Three Months Ended September 30,								Nine Months Ended September 30,
	2020				2019				2020				2019
Contract drilling	$	115,054	55.5	%	$	317,035	53.0	%	$	553,552	61.3	%	$	1,037,565	52.4	%
Pressure pumping		71,973	34.7	%		208,637	34.9	%		256,613	28.4	%		707,246	35.7	%
Directional drilling		10,271	5.0	%		47,037	7.9	%		56,498	6.3	%		150,214	7.6	%
Other operations		9,843	4.8	%		25,743	4.2	%		36,785	4.0	%		83,363	4.3	%
	$	207,141	100.0	%	$	598,452	100.0	%	$	903,448	100.0	%	$	1,978,388	100.0	%

Contract Drilling

Contract drilling revenues accounted for 55.5% of our consolidated third quarter 2020 revenues and decreased 63.7% from the comparable 2019 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, 2020, our rig fleet included 198 APEX^® rigs, of which 150 were 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, 2020 was approximately $307 million. Approximately 29% of the total contract drilling backlog at September 30, 2020 is reasonably expected to remain at September 30, 2021. 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, 2020. 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 notice for the rig to be placed on standby, our backlog calculation uses the standby rate for the period over which we expect to receive the standby rate. 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 34.7% of our consolidated third quarter 2020 revenues and decreased 65.5% from the comparable 2019 period. As of September 30, 2020, we had approximately 1.3 million horsepower in our pressure pumping fleet. The pressure pumping market remains oversupplied. In response to oversupplied market conditions, we implemented changes that are intended to further streamline our operations, improve our efficiencies, and reduce our overall cost structure, while maintaining our customer service levels.

Directional Drilling

Directional drilling revenues accounted for 5.0% of our consolidated third quarter 2020 revenues and decreased 78.2% from the comparable 2019 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 4.8% of our consolidated third quarter 2020 revenues and decreased 61.8% from the comparable 2019 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.

For the three and nine months ended September 30, 2020 and 2019, our operating loss consisted of the following (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2020			2019			2020			2019
Contract drilling	$	(47,214	)	$	(169,528	)	$	(481,974	)	$	(131,817	)
Pressure pumping		(30,856	)		(42,962	)		(134,896	)		(76,138	)
Directional drilling		(9,912	)		(32,501	)		(34,892	)		(43,458	)
Other operations		(6,421	)		(39,192	)		(35,547	)		(51,713	)
Corporate		(20,163	)		(23,122	)		(80,751	)		(75,687	)
	$	(114,566	)	$	(307,305	)	$	(768,060	)	$	(378,813	)

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 2020 was $112 million compared to a net loss of $262 million for the third quarter of 2019.

Results of Operations

The following tables summarize results of operations by business segment for the three months ended September 30, 2020 and 2019:

Contract Drilling	2020			2019			% Change
	(dollars in thousands)
Revenues	$	115,054		$	317,035			(63.7	)%
Direct operating costs		59,117			188,934			(68.7	)%
Margin ⁽¹⁾		55,937			128,101			(56.3	)%
Selling, general and administrative		876			1,510			(42.0	)%
Depreciation, amortization and impairment		102,275			296,119			(65.5	)%
Operating loss	$	(47,214	)	$	(169,528	)		(72.1	)%
Operating days ⁽²⁾		5,499			13,081			(58.0	)%
Average revenue per operating day	$	20.92		$	24.24			(13.7	)%
Average direct operating costs per operating day	$	10.75		$	14.44			(25.6	)%
Average margin per operating day ⁽¹⁾	$	10.17		$	9.79			3.9	%
Average rigs operating		60			142			(58.0	)%
Capital expenditures	$	9,502		$	34,752			(72.7	)%

⁽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 2020, our average number of rigs operating was 60, compared to 142 in the third quarter of 2019. Our average revenue per operating day is largely dependent on the pricing terms of our rig contracts. The decrease in average revenue per operating day includes the impact of a higher percentage of rigs on standby during the 2020 period.

Revenues and direct operating costs decreased primarily due to a decrease in operating days. Average direct operating costs per operating day decreased due to cost reduction efforts and a higher percentage of rigs on standby during the 2020 period. Rigs on standby have very little associated cost. Average margin per operating day in the third quarter of 2020 included benefits from lump sum early termination revenue and a credit to operating costs for sales and use taxes.

Depreciation, amortization and impairment expense decreased primarily due to a charge of $173 million resulting from the retirement of 36 legacy non-APEX® drilling rigs and related equipment in the third quarter of 2019, which resulted in no depreciation expense being recorded for this equipment in 2020.

The decrease in capital expenditures was primarily due to higher maintenance capital expenditures in the third quarter of 2019 when activity levels were higher and reduced capital expenditures in 2020 due to lower activity.

Pressure Pumping	2020			2019			% Change
	(dollars in thousands)
Revenues	$	71,973		$	208,637			(65.5	)%
Direct operating costs		63,721			176,306			(63.9	)%
Margin ⁽¹⁾		8,252			32,331			(74.5	)%
Selling, general and administrative		2,004			3,154			(36.5	)%
Depreciation, amortization and impairment		37,104			72,139			(48.6	)%
Operating loss	$	(30,856	)	$	(42,962	)		(28.2	)%
Fracturing jobs		69			126			(45.2	)%
Other jobs		180			173			4.0	%
Total jobs		249			299			(16.7	)%
Average revenue per fracturing job	$	960.70		$	1,631.71			(41.1	)%
Average revenue per other job	$	31.58		$	17.58			79.6	%
Average revenue per total job	$	289.05		$	697.78			(58.6	)%
Average direct operating costs per total job	$	255.91		$	589.65			(56.6	)%
Average margin per total job ⁽¹⁾	$	33.14		$	108.13			(69.4	)%
Margin as a percentage of revenues ⁽¹⁾		11.5	%		15.5	%		(26.0	)%
Capital expenditures	$	1,653		$	19,826			(91.7	)%

⁽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. Our average revenue per fracturing job is largely dependent on the pricing terms of our pressure pumping contracts. We completed 69 fracturing jobs during the third quarter of 2020, compared to 126 fracturing jobs in the third quarter of 2019. Our average revenue per fracturing job was $0.961 million in the third quarter of 2020, compared to $1.632 million in the third quarter of 2019.

Revenues and direct operating costs decreased primarily due to a decline in the number of fracturing jobs. Average revenue and direct operating costs per job were impacted by lower demand.

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

Depreciation, amortization and impairment expense decreased due to the significant decline in capital expenditures and a $20.5 million write-down of pressure pumping equipment in the third quarter of 2019, which resulted in no depreciation expense being recorded for this equipment in the third quarter of 2020.

Directional Drilling	2020			2019			% Change
	(dollars in thousands)
Revenues	$	10,271		$	47,037			(78.2	)%
Direct operating costs		9,754			56,215			(82.6	)%
Margin ⁽¹⁾		517			(9,178	)	NA
Selling, general and administrative		829			2,805			(70.4	)%
Depreciation, amortization, and impairment		9,600			20,518			(53.2	)%
Operating loss	$	(9,912	)	$	(32,501	)		(69.5	)%
Capital expenditures	$	510		$	5,559			(90.8	)%

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

Revenue decreased by $36.8 million from the third quarter of 2019 primarily due to decreased job activity.

Directional drilling direct operating costs decreased by $46.5 million primarily due to lower direct costs from decreased job activity and cost reduction efforts.

Selling, general and administrative expenses decreased 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 primarily due to the write-down of directional drilling equipment, which resulted in no depreciation expense being recorded for this equipment in 2020.

Other Operations	2020			2019			% Change
	(dollars in thousands)
Revenues	$	9,843		$	25,743			(61.8	)%
Direct operating costs		8,665			31,759			(72.7	)%
Margin ⁽¹⁾		1,178			(6,016	)	NA
Selling, general and administrative		747			5,149			(85.5	)%
Depreciation, depletion, amortization and impairment		6,852			10,227			(33.0	)%
Impairment of goodwill		—			17,800			(100.0	)%
Operating loss	$	(6,421	)	$	(39,192	)		(83.6	)%
Capital expenditures	$	1,704		$	7,191			(76.3	)%

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

Other operations revenue decreased by $15.9 million from the third quarter of 2019 primarily due to a decrease in the volume of services provided by our oilfield rentals business and a decline in the average price per barrel of crude oil received by our oil and natural gas assets.

Other operations direct operating costs decreased by $23.1 million and selling, general and administrative expense decreased by $4.4 million primarily due to the decision to transition away from our engineering and manufacturing efforts in Calgary during the third quarter of 2019. Charges associated with this decision that were recorded in the third quarter of 2019 totaled $12.4 million for direct operating costs and $2.2 million for selling, general and administrative expense. The $12.4 million charge to direct operating costs was primarily comprised of inventory write-offs. Additionally, a portion of the period-over-period decrease was due to a reduction in the volume of services provided by our oilfield rentals business.

Depreciation, depletion, amortization and impairment decreased over the comparable prior year period primarily due to a decrease in production from our oil and natural gas assets as well as reduced capital expenditures and certain equipment reaching the end of its depreciable life in our oilfield rentals business.

There were no impairments of goodwill in the third quarter of 2020 as all of the goodwill associated with our oilfield rentals and electrical controls and automation businesses was previously impaired during the third quarter of 2019.

Corporate	2020			2019			% Change
	(dollars in thousands)
Selling, general and administrative	$	17,899		$	21,613			(17.2	)%
Depreciation	$	1,488		$	1,761			(15.5	)%
Other operating expenses (income), net
Net loss (gain) on asset disposals	$	(896	)	$	(637	)		40.7	%
Legal-related expenses and settlements, net of insurance reimbursements		830			—		NA
Research and development		842			385			118.7	%
Other operating expenses (income), net	$	776		$	(252	)	NA
Interest income	$	238		$	1,693			(85.9	)%
Interest expense	$	11,288		$	20,739			(45.6	)%
Other income	$	512		$	119			330.3	%
Capital expenditures	$	73		$	700			(89.6	)%

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

Other operating expenses (income), net includes net gains or losses 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.

Interest expense was lower in the three months ended September 30, 2020. Interest expense for the three months ended September 30, 2019 included a loss on debt extinguishment of $8.2 million as a result of full prepayment of our 4.97% Series A Senior Notes due October 5, 2020 (the “Series A Notes”).

The following tables summarize results of operations by business segment for the nine months ended September 30, 2020 and 2019:

Contract Drilling	2020			2019			% Change
	(dollars in thousands)
Revenues	$	553,552		$	1,037,565			(46.6	)%
Direct operating costs		309,664			609,928			(49.2	)%
Margin ⁽¹⁾		243,888			427,637			(43.0	)%
Restructuring expenses		2,430			—		NA
Other operating expenses (income), net		(4,155	)		—		NA
Selling, general and administrative		3,684			4,616			(20.2	)%
Depreciation, amortization and impairment		328,843			554,838			(40.7	)%
Impairment of goodwill		395,060			—		NA
Operating income (loss)	$	(481,974	)	$	(131,817	)		265.6	%
Operating days ⁽²⁾		24,184			43,253			(44.1	)%
Average revenue per operating day	$	22.89		$	23.99			(4.6	)%
Average direct operating costs per operating day	$	12.80		$	14.10			(9.2	)%
Average margin per operating day ⁽¹⁾	$	10.08		$	9.89			1.9	%
Average rigs operating		88			158			(44.3	)%
Capital expenditures	$	101,448		$	158,141			(35.8	)%

⁽¹⁾

Margin is defined as revenues less direct operating costs and excludes restructuring expenses, other operating expenses (income), net, 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 first nine months of 2020, our average number of rigs operating was 88, compared to 158 in the same period of 2019. Our average revenue per operating day is largely dependent on the pricing terms of our rig contracts. The decrease in average revenue per operating day includes the impact of a higher percentage of rigs on standby during the 2020 period.

Revenues and direct operating costs decreased primarily due to a decrease in operating days. Average direct operating costs per operating day decreased due to cost reduction efforts and a higher percentage of rigs on standby during the 2020 period. Rigs on standby have very little associated cost. Average margin per operating day in the 2020 period included benefits from lump sum early termination revenue and a credit to operating costs for sales and use taxes.

Restructuring expenses were recognized in the second quarter of 2020 and primarily related to severance costs. See Note 16 of Notes to unaudited condensed consolidated financial statements for additional information.

The increase in other operating expenses (income), net is primarily due to an insurance reimbursement for damaged drilling equipment.

Depreciation, amortization and impairment expense decreased primarily due to the retirement of 36 legacy non-APEX® drilling rigs and related equipment in the third quarter of 2019, which resulted in no depreciation expense being recorded for this equipment in 2020.

All of the goodwill associated with our contract drilling reporting unit was impaired during the three months ended March 31, 2020. See Note 6 of Notes to unaudited condensed consolidated financial statements for additional information.

The decrease in capital expenditures was primarily due to higher maintenance capital expenditures in 2019 when activity levels were higher and reduced capital expenditures in 2020 due to lower activity.

Pressure Pumping	2020			2019			% Change
	(dollars in thousands)
Revenues	$	256,613		$	707,246			(63.7	)%
Direct operating costs		234,844			585,191			(59.9	)%
Margin ⁽¹⁾		21,769			122,055			(82.2	)%
Restructuring expenses		31,331			—		NA
Selling, general and administrative		6,748			9,734			(30.7	)%
Depreciation, amortization and impairment		118,586			188,459			(37.1	)%
Operating loss	$	(134,896	)	$	(76,138	)		77.2	%
Fracturing jobs		193			412			(53.2	)%
Other jobs		541			629			(14.0	)%
Total jobs		734			1,041			(29.5	)%
Average revenue per fracturing job	$	1,251.37		$	1,687.39			(25.8	)%
Average revenue per other job	$	27.91		$	19.14			45.8	%
Average revenue per total job	$	349.61		$	679.39			(48.5	)%
Average direct operating costs per total job	$	319.95		$	562.14			(43.1	)%
Average margin per total job ⁽¹⁾	$	29.66		$	117.25			(74.7	)%
Margin as a percentage of revenues ⁽¹⁾		8.5	%		17.3	%		(50.8	)%
Capital expenditures	$	17,880		$	90,028			(80.1	)%

⁽¹⁾

Margin is defined as revenues less direct operating costs and excludes restructuring expenses, 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. Our average revenue per fracturing job is largely dependent on the pricing terms of our pressure pumping contracts. We completed 193 fracturing jobs during the first nine months of 2020, compared to 412 fracturing jobs in the same period of 2019. Our average revenue per fracturing job was $1.251 million in the first nine months of 2020, compared to $1.687 million in the same period of 2019.

Revenues and direct operating costs decreased primarily due to a decline in the number of fracturing jobs. Average revenue and direct operating costs per job were impacted by lower demand and cost reduction efforts.

Restructuring expenses were recognized in the second quarter of 2020. These restructuring expenses included $7.3 million related to ROU asset abandonments, $3.5 million of severance costs and $20.4 million of contract termination costs. See Note 16 of Notes to unaudited condensed consolidated financial statements for additional information.

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

Depreciation, amortization and impairment expense decreased due to the significant decline in capital expenditures and write-down of pressure pumping equipment in the nine months ended September 30, 2019, which resulted in no depreciation expense being recorded for this equipment in 2020.

Directional Drilling	2020			2019			% Change
	(dollars in thousands)
Revenues	$	56,498		$	150,214			(62.4	)%
Direct operating costs		54,348			143,919			(62.2	)%
Margin ⁽¹⁾		2,150			6,295			(65.8	)%
Restructuring expenses		3,175			—		NA
Selling, general and administrative		4,169			7,998			(47.9	)%
Depreciation, amortization, and impairment		29,698			41,755			(28.9	)%
Operating loss	$	(34,892	)	$	(43,458	)		(19.7	)%
Capital expenditures	$	4,562		$	11,121			(59.0	)%

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

Directional drilling revenue decreased by $93.7 million from the nine months ended September 30, 2019 primarily due to decreased job activity.

Directional drilling direct operating costs decreased by $89.6 million primarily due to lower direct costs from decreased job activity and cost reduction efforts.

Restructuring expenses were recognized in the second quarter of 2020 and were primarily attributable to severance and ROU asset abandonments. See Note 16 of Notes to unaudited condensed consolidated financial statements for additional information.

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

Other Operations	2020			2019			% Change
	(dollars in thousands)
Revenues	$	36,785		$	83,363			(55.9	)%
Direct operating costs		33,775			71,144			(52.5	)%
Margin ⁽¹⁾		3,010			12,219			(75.4	)%
Restructuring expenses		501			—		NA
Selling, general and administrative		2,969			12,660			(76.5	)%
Depreciation, depletion, amortization and impairment		35,087			33,472			4.8	%
Impairment of goodwill		—			17,800			(100.0	)%
Operating loss	$	(35,547	)	$	(51,713	)		(31.3	)%
Capital expenditures	$	9,776		$	21,194			(53.9	)%

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

Other operations revenue decreased by $46.6 million from the nine months ended September 30, 2019 primarily due to a decrease in the volume of services provided by our oilfield rentals business and a decline in the average price per barrel of crude received by our oil and natural gas assets.

Other operations direct operating costs decreased by $37.4 million from the nine months ended September 30, 2019 primarily due to a decrease in the volume of services provided by our oilfield rentals business. Additionally, a portion of the decrease is attributed to the decision to transition away from our engineering and manufacturing efforts in Calgary during 2019. Charges associated with this decision totaled $12.4 million for direct operating costs during the nine months ended September 30, 2019, which were primarily comprised of inventory write-offs.

Restructuring expenses were recognized in the second quarter of 2020 and related to severance costs. See Note 16 of Notes to unaudited condensed consolidated financial statements for additional information.

Selling, general and administrative expense decreased primarily as a result of cost reduction efforts in addition to the transition away from our engineering and manufacturing efforts in Calgary during 2019. Charges associated with that decision totaled $2.2 million for the nine months ended September 30, 2019.

Depreciation, depletion, amortization and impairment increased over the comparable prior year period primarily due to a $11.2 million impairment related to certain of our oil and natural gas assets recorded in 2020, whereas $2.2 million of oil and natural gas property impairments were recorded in 2019. The increased oil and natural gas property impairments were partially offset by decreased 2020 depletion on our oil and natural gas assets, which was primarily due to a decrease in production.

There were no impairments of goodwill during the nine months ended September 30, 2020 as all of the goodwill associated with our oilfield rentals and electrical controls and automation businesses was previously impaired during the nine months ended September 30, 2019.

Corporate	2020			2019			% Change
	(dollars in thousands)
Selling, general and administrative	$	59,122		$	66,672			(11.3	)%
Restructuring expenses		901		$	—		NA
Depreciation	$	4,987		$	5,338			(6.6	)%
Other operating expenses (income), net
Net loss (gain) on asset disposals	$	(3,357	)	$	(11,153	)		(69.9	)%
Legal-related expenses and settlements, net of insurance reimbursements		1,680			(3,471	)	NA
Research and development		2,580			2,111			22.2	%
Other		9,232			12,596			(26.7	)%
Other operating expenses (income), net	$	10,135		$	83			12,110.8	%
Credit loss expense	$	5,606			3,594			56.0	%
Interest income	$	1,229		$	4,481			(72.6	)%
Interest expense	$	33,496		$	47,021			(28.8	)%
Other income	$	682		$	328			107.9	%
Capital expenditures	$	1,377		$	2,804			(50.9	)%

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

Other operating expenses (income), net includes charges of $9.2 million and $12.7 million in 2020 and 2019, respectively 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. The deposit related to the capacity reservation agreement has no balance remaining subsequent to the charge recorded in the second quarter of 2020.

A provision for credit losses was recognized in the nine months ended September 30, 2020 with respect to accounts receivable balances that are estimated to be uncollectible.

Interest expense was lower in the nine months ended September 30, 2020. Interest expense for the nine months ended September 30, 2019 included a loss on debt extinguishment of $8.2 million as a result of full prepayment of the Series A Notes.

Income Taxes

Liquidity and Capital Resources

We significantly reduced our planned capital expenditures for 2020. We currently expect our capital expenditures for 2020 to total approximately $150 million.

While oilfield services activity and revenues have declined significantly throughout 2020, we have aligned our cost structure with the changing activity levels and enhanced our liquidity position. Our liquidity as of September 30, 2020 included $304 million of cash and cash equivalents, $57 million of which was added during the third quarter, and approximately $600 million available under our revolving credit facility.

On January 19, 2018, we completed an offering of $525 million in aggregate principal amount of our 3.95% Senior Notes due 2028 (the “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 (the “Term Loan Agreement”), which 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. 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 our 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 repaid $50 million of the borrowings under the Term Loan Agreement on December 16, 2019, and we had $100 million in outstanding borrowings under the Term Loan Agreement as of September 30, 2020.

On November 15, 2019, we completed an offering of $350 million in aggregate principal amount of our 5.15% Senior Notes due 2029 (the “2029 Notes”). The net proceeds before offering expenses were approximately $347 million. On December 16, 2019, we used a portion of the net proceeds from the offering to prepay our 4.27% Series B Senior Notes due June 14, 2022 (the “Series B Notes”). The total amount of the prepayment, including the applicable “make-whole” premium, was approximately $315 million, plus accrued interest to the prepayment date. The remaining net proceeds and available cash on hand was used to repay $50 million of the borrowings under the Term Loan Agreement.

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.

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, 2020, our sources of cash flow included:

•

$283 million from operating activities, and

•

$17.8 million in proceeds from the disposal of property and equipment and from insurance claims.

During the nine months ended September 30, 2020, we used $15.1 million to pay dividends on our common stock, $21.1 million for repurchases of our common stock and $135 million:

•

to make capital expenditures for the betterment and refurbishment of drilling and pressure pumping equipment and, to a much lesser extent, equipment for our other businesses,

•

to acquire and procure equipment 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, 2020 as follows:

	Per Share		Total
			(in thousands)
Paid on March 19, 2020	$	0.04	$	7,629
Paid on June 18, 2020	$	0.02	$	3,735
Paid on September 17, 2020	$	0.02	$	3,746
	$	0.08	$	15,110

We may, at any time and from time to time, seek to retire or purchase our outstanding debt for cash through open-market purchases, privately negotiated transactions, redemptions or otherwise. Such repurchases, if any, will be upon such terms and at such prices as we may determine, and will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

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, 2020, we had remaining authorization to purchase approximately $130 million of our outstanding common stock under the stock buyback program.

Treasury stock acquisitions during the nine months ended September 30, 2020 were as follows (dollars in thousands):

	Shares		Cost
Treasury shares at beginning of period		77,336,387	$	1,345,134
Purchases pursuant to stock buyback program		5,826,266		20,000
Acquisitions pursuant to long-term incentive plan ⁽¹⁾		222,550		1,129
Treasury shares at end of period		83,385,203	$	1,366,263

⁽¹⁾

We withheld 222,550 shares during the first three quarters of 2020 with respect to 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, as amended, and not pursuant to the stock buyback program.

2019 Term Loan Agreement — On August 22, 2019, we entered into the Term Loan Agreement among us, as borrower, Wells Fargo Bank, National Association, as administrative agent and lender and the other lender party thereto.

As of September 30, 2020, we had $100 million in borrowings outstanding under the Term Loan Agreement at a LIBOR interest rate of 1.52 %.

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, 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. On March 27, 2020, we entered into Amendment No. 2 to Amended and Restated Credit Agreement to, among other things, extend the maturity date for $550 million of revolving credit commitments of certain lenders under the Credit Agreement from March 27, 2024 to March 27, 2025. We have the option, subject to certain conditions, to exercise one additional one-year extension of the maturity date.

2028 Senior Notes and 2029 Senior Notes — On January 19, 2018, we completed an offering of $525 million in aggregate principal amount of our 2028 Notes. The net proceeds before offering expenses were approximately $521 million, of which we used $239 million to repay amounts outstanding under our revolving credit facility. On November 15, 2019, we completed an offering of $350 million in aggregate principal amount of our 2029 Notes. The net proceeds before offering expenses were approximately $347 million. We used a portion of the net proceeds from the offering to prepay our Series B Notes. The remaining net proceeds and available cash on hand was used to repay $50 million of the borrowings under the Term Loan Agreement.

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.

We pay interest on the 2029 Notes on May 15 and November 15 of each year. The 2029 Notes will mature on November 15, 2029. The 2029 Notes bear interest at a rate of 5.15% per annum.

Commitments— As of September 30, 2020, we maintained letters of credit in the aggregate amount of $60.8 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, 2020, no amounts had been drawn under the letters of credit.

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,
	2020			2019			2020			2019
	(in thousands)
Net loss	$	(112,111	)	$	(261,719	)	$	(697,165	)	$	(339,780	)
Income tax benefit		(12,993	)		(64,513	)		(102,480	)		(81,245	)
Net interest expense		11,050			19,046			32,267			42,540
Depreciation, depletion, amortization and impairment		157,319			400,764			517,201			823,862
Impairment of goodwill		—			17,800			395,060			17,800
Adjusted EBITDA	$	43,265		$	111,378		$	144,883		$	463,177

Critical Accounting Policies

In addition to established accounting policies, our consolidated financial statements are impacted by certain estimates and assumptions made by management. The following is a discussion of our critical accounting policies pertaining to property and equipment, goodwill, revenue recognition and the use of estimates.

Property and equipment — Property and equipment, including betterments that extend the useful life of the asset, are stated at cost. Maintenance and repairs are charged to expense when incurred. We provide for the depreciation of our property and equipment using the straight-line method over the estimated useful lives. Our method of depreciation does not change when equipment becomes idle; we continue to depreciate idled equipment on a straight-line basis. No provision for salvage value is considered in determining depreciation of our property and equipment.

as our 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.

2020 Triggering Event Assessment — Due to the decline in the market price of our common stock and commodity prices in the first quarter of 2020, we lowered our expectations with respect to future activity levels in certain of our operating segments. We deemed it necessary to assess the recoverability of our contract drilling, pressure pumping, directional drilling and oilfield rentals asset groups as of March 31, 2020. We performed an analysis as required by ASC 360-10-35 to assess the recoverability of the asset groups within our contract drilling, pressure pumping, directional drilling and oilfield rentals operating segments as of March 31, 2020. With respect to these asset groups, future cash flows were estimated over the expected remaining life of the assets, and we 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 15%, 22%, 3% and 9%, respectively.

For the assessment performed as of March 31, 2020, the expected cash flows for our asset groups included assumptions about utilization, revenue and costs for our equipment and services that were estimated based upon our 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 second half of 2019 and first quarter of 2020 and would begin to recover in 2022 in response to improved oil prices. While we believe these assumptions with respect to future oil pricing are reasonable, actual future prices and activity levels may vary significantly from the ones that were assumed. The timeframe over which oil prices and activity levels may recover is highly uncertain.

Goodwill — Goodwill is considered to have an indefinite useful economic life and is not amortized. 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. Our reporting units for impairment testing are our operating segments. We determine 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, we 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.

Use of estimates — The preparation of financial statements in conformity with U.S. GAAP requires management to make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from such estimates.

Key estimates used by management include:

•

allowance for doubtful accounts,

•

depreciation, depletion and amortization,

•

fair values of assets acquired and liabilities assumed in acquisitions,

•

goodwill and long-lived asset impairments, and

•

reserves for self-insured levels of insurance coverage.

For additional information on our accounting policies, see Note 1 of Notes to unaudited condensed consolidated financial statements included as a part of this Report.

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. Oil prices remain extremely volatile, as the closing price of oil (WTI-Cushing) reached a first quarter 2020 high of $63.27 per barrel on January 6, 2020, declined to negative $36.98 per barrel on April 20, 2020, and closed at $40.69 per barrel on October 19, 2020. In response to the rapid decline in commodity prices, E&P companies acted swiftly to reduce drilling and completion activity starting late in the first quarter.

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, as well as our customers’ ability to access sources of capital to fund their operating and capital expenditures. A decline in demand for oil and natural gas, prolonged low oil or natural gas prices, expectations of decreases in oil and natural gas prices or a reduction in the ability of our customers to access capital, 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 historically moderate or 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, 2020, 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 amounts owed under the Reimbursement Agreement.

Loans under the Credit Agreement bear interest by reference, at our election, to the LIBOR rate or base rate. The applicable margin on LIBOR rate loans varies from 1.00% to 2.00% and the applicable margin on base rate loans varies from 0.00% to 1.00%, in each case determined based on our credit rating. As of September 30, 2020, the applicable margin on LIBOR rate loans was 1.75% and the applicable margin on base rate loans was 0.75%. As of September 30, 2020, we had no borrowings outstanding under our revolving credit facility. The interest rate on borrowings outstanding under our revolving credit facility is variable and adjusts at each interest payment date based on our election of LIBOR or the base rate.

Under the Reimbursement Agreement, we will reimburse Scotiabank on demand for any amounts that Scotiabank has disbursed under any letters of credit. We are obligated to pay Scotiabank interest on all amounts not paid by us on the date of demand or when otherwise due at the LIBOR rate plus 2.25% per annum. As of September 30, 2020, 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, 2020.

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

PART II — OTHER INFORMATION

ITEM 1. Legal Proceedings

ITEM 1A. Risk Factors

The Rapid Decline in Crude Oil Prices, Including as a Result of Economic Repercussions from the Covid-19 Pandemic, Have Had, and Are Expected to Continue to Have, a Significant Impact on Our Business, and, Depending on the Effectiveness of Oil Production Cuts and the Duration of the Pandemic and Its Effect on the Oil and Gas Industry, Could Have a Material Adverse Effect on Our Business, Liquidity, Consolidated Results of Operations and Consolidated Financial Condition.

The rapid decline in crude oil prices, including as a result of economic repercussions from the recent COVID-19 pandemic, have contributed to significant volatility, uncertainty, and turmoil in the oil and gas industry. These events have affected our business and have exacerbated the potential negative impact from many of the risks described in our Form 10-K for the year ended December 31, 2019, including those relating to our customers’ capital spending and trends in oil and natural gas prices.

In early March 2020, OPEC+ was initially unable to reach an agreement to continue to impose limits on the production of crude oil, and shortly thereafter the World Health Organization determined the COVID-19 outbreak to be a pandemic. The convergence of these events created the unprecedented dual impact of a global oil demand decline coupled with the risk of a substantial increase in supply. Oil demand has significantly deteriorated as a result of the virus outbreak and corresponding preventative measures taken around the world to mitigate the spread of the virus. While OPEC+ agreed in April 2020 to cut production, downward pressure on commodity prices could continue for the foreseeable future.

Given the nature and significance of the events described above, we are not able to enumerate all potential risks to our business from the decline in crude oil prices and the COVID-19 pandemic; however, we believe that in addition to the impacts described above, other current and potential impacts of these recent events include, but are not limited to:

•

liquidity challenges, including impacts related to delayed customer payments and payment defaults associated with customer liquidity issues and bankruptcies;

•

customers, suppliers and other third parties seeking to terminate, reject, renegotiate or otherwise avoid, and otherwise failing to perform, their contractual obligations to us;

•

additional credit rating downgrades of our corporate debt and potentially higher borrowing costs in the future;

•

a need to preserve liquidity, which could result in a reduction or suspension of our quarterly dividend or a delay or change in our capital investment plan;

•

cybersecurity issues, as digital technologies may become more vulnerable and experience a higher rate of cyberattacks in the current environment of remote connectivity;

•

litigation risk and possible loss contingencies related to COVID-19 and its impact, including with respect to commercial contracts, employee matters and insurance arrangements;

•

disruption to our supply chain for raw materials essential to our business;

•

a further reduction of our workforce to adjust to market conditions, including severance payments, retention issues, and an inability to hire employees when market conditions improve;

•

additional costs associated with rationalization of our portfolio of real estate facilities, including possible exit of leases and facility closures to align with expected activity and workforce capacity;

•

additional asset impairments, along with other accounting charges;

•

infections and quarantining of our employees and the personnel of our customers, suppliers and other third parties in areas in which we operate and delays or suspensions of operations resulting therefrom;

•

changes in the regulation of the production of hydrocarbons, such as the imposition of limitations on the production of oil and gas by states or other jurisdictions, that may result in additional limits on demand for our services;

•

actions undertaken by national, regional and local governments and health officials to contain the virus or treat its effects; and

•

a structural shift in the global economy and its demand for oil and natural gas as a result of changes in the way people work, travel and interact, or in connection with a global recession or depression.

Given the dynamic nature of these events, we cannot reasonably estimate the period of time that the depressed commodity prices or COVID-19 pandemic and related market conditions will persist, the full extent of the impact they will have on our business, financial condition, results of operations or cash flows or the pace or extent of any subsequent recovery.

The events described above have had, and are expected to continue to have, a significant impact on our business, and, depending on the effectiveness of oil production cuts and the duration of the pandemic and its effect on the oil and gas industry, could have, a material adverse effect on our business, liquidity, consolidated results of operations and consolidated financial condition. We cannot predict when the continuing impact on us will end, and depending on the duration of the pandemic and its severity, this impact could worsen. For more information, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Management Overview.”

Anti-takeover Measures in Our Charter Documents and Under State Law Could Discourage an Acquisition and Thereby Affect the Related Purchase Price.

We are a Delaware corporation subject to the Delaware General Corporation Law, including Section 203, an anti-takeover law. Our restated certificate of incorporation authorizes our Board of Directors to issue up to one million shares of preferred stock and to determine the price, rights (including voting rights), conversion ratios, preferences and privileges of that stock without further vote or action by the holders of the common stock. It also prohibits stockholders from acting by written consent without the holding of a meeting. In addition, our bylaws impose certain advance notification requirements as to business that can be brought by a stockholder before annual stockholder meetings and as to persons nominated as directors by a stockholder. As a result of these measures and others, potential acquirers might find it more difficult or be discouraged from attempting to effect an acquisition transaction with us. This may deprive holders of our securities of certain opportunities to sell or otherwise dispose of the securities at above-market prices pursuant to any such transactions. In addition, we have adopted a stockholder rights agreement that could make it more difficult for a third-party to acquire our common stock without the approval of our Board of Directors.

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, 2020.

							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 2020		57,284	$	3.39		—	$	130,000
August 2020		—	$	—		—	$	130,000
September 2020		—	$	—		—	$	130,000
Total		57,284				—

⁽¹⁾

We withheld 57,284 shares during the third quarter of 2020 with respect to employees’ tax withholding obligations upon the vesting of 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, as amended, 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.

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 our 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 our 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 our 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 our 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 our Current Report on Form 8-K and incorporated herein by reference).

3.6		Certificate of Designation of the Series A Junior Participating Preferred Stock of Patterson-UTI Energy, Inc., dated April 22, 2020 (filed April 23, 2020 as Exhibit 3.1 to our Current Report on Form 8-K and incorporated herein by reference).

4.1		Stockholder Rights Agreement, dated as of April 22, 2020, by and between Patterson-UTI Energy, Inc. and Continental Stock Transfer & Trust Company, as rights agent (which includes the Form of Rights Certificate as Exhibit B thereto) (filed April 23, 2020 as Exhibit 4.1 to our Current Report on Form 8-K and incorporated herein by reference).

4.2		First Amendment to Stockholder Rights Agreement, dated as of July 22, 2020, by and between Patterson-UTI Energy, Inc. and Continental Stock Transfer & Trust Company, as rights agent (filed July 23, 2020 as Exhibit 4.1 to our 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 our Quarterly Report on Form 10-Q for the quarter ended September 30, 2020, has been formatted in Inline XBRL.

*	filed herewith

SIGNATURE

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

PATTERSON-UTI ENERGY, INC.

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

Date: October 27, 2020