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~~June 30, ~~2021~~2022


☐		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

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.

~~215,112,196~~216,821,730 shares of common stock, $0.01 par value, as of ~~October~~July 28, ~~2021.~~2022.

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~~income (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	2524
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	3937
ITEM 4.	Controls and Procedures	4037

	PART II — OTHER INFORMATION

ITEM 1.	Legal Proceedings	41
~~ITEM 1A.~~	~~Risk Factors~~	4138
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4238
ITEM 6.	Exhibits	4339
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,			June 30,			December 31,
	2021			2020			2022			2021
ASSETS
Current assets:
Cash and cash equivalents	$	191,284		$	224,915		$	19,636		$	117,524
Accounts receivable, net of allowance for credit losses of $9,993 and $10,842 at September 30, 2021 and December 31, 2020, respectively		263,186			160,214
Accounts receivable, net of allowance for credit losses of $8,216 and $8,493 at June 30, 2022 and December 31, 2021, respectively								473,153			356,083
Federal and state income taxes receivable		64			4,428			187			67
Inventory		34,924			33,085			53,528			42,359
Other		54,074			55,314			74,714			67,620
Total current assets		543,532			477,956			621,218			583,653
Property and equipment, net		2,424,725			2,761,041			2,289,371			2,331,755
Right of use asset		15,376			16,850			22,815			19,024
Intangible assets		21,052			30,087
Intangible assets, net								7,166			7,537
Deposits on equipment purchases		1,782			1,716			5,212			849
Other		10,996			11,419			11,376			11,055
Deferred tax assets, net								2,819			3,975
Total assets	$	3,017,463		$	3,299,069		$	2,959,977		$	2,957,848
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	165,779		$	91,622		$	252,692		$	190,219
Federal and state income taxes payable								803			232
Accrued liabilities		167,128			175,004			189,203			238,511
Lease liability		5,942			7,096			5,723			6,891
Total current liabilities		338,849			273,722			448,421			435,853
Long-term lease liability		15,798			19,118			21,607			18,108
Long-term debt, net of debt discount and issuance costs of $6,651 and $7,271 at September 30, 2021 and December 31, 2020, respectively		902,104			901,484
Long-term debt, net of debt discount and issuance costs of $6,016 and $6,432 at June 30, 2022 and December 31, 2021, respectively								877,739			852,323
Deferred tax liabilities, net		22,922			77,676			25,464			29,234
Other		12,145			11,010			10,665			12,843
Total liabilities		1,291,818			1,283,010			1,383,896			1,348,361
Commitments and contingencies (see Note 10)
Commitments and contingencies (see Note 9)
Stockholders' equity:
Preferred stock, par value $0.01; authorized 1,000,000 shares, 0 shares issued		—			—			0			0
Common stock, par value $0.01; authorized 400,000,000 shares with 272,885,704 and 271,028,688 issued and 189,049,158 and 187,626,366 outstanding at September 30, 2021 and December 31, 2020, respectively		2,729			2,710
Common stock, par value $0.01; authorized 400,000,000 shares with 302,325,853 and 299,268,967 issued and 216,821,730 and 215,139,972 outstanding at June 30, 2022 and December 31, 2021, respectively								3,023			2,993
Additional paid-in capital		2,919,090			2,902,236			3,191,678			3,171,536
Retained earnings		167,860			472,014
Retained deficit								(222,714	)		(198,316	)
Accumulated other comprehensive income		5,853			5,412			0			5,915
Treasury stock, at cost, 83,836,546 and 83,402,322 shares at September 30, 2021 and December 31, 2020, respectively		(1,369,887	)		(1,366,313	)
Treasury stock, at cost, 85,504,123 and 84,128,995 shares at June 30, 2022 and December 31, 2021, respectively								(1,395,906	)		(1,372,641	)
Total stockholders' equity		1,725,645			2,016,059			1,576,081			1,609,487
Total liabilities and stockholders' equity	$	3,017,463		$	3,299,069		$	2,959,977		$	2,957,848

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						Three Months Ended						Six Months Ended
	September 30,						September 30,						June 30,						June 30,
	2021			2020			2021			2020			2022			2021			2022			2021
Operating revenues:
Contract drilling	$	157,925		$	115,054		$	433,158		$	553,552		$	304,586		$	141,732		$	561,226		$	275,233
Pressure pumping		152,634			71,973			340,464			256,613			238,376			111,991			427,966			187,830
Directional drilling		31,728			10,271			76,267			56,498			54,825			24,869			98,159			44,539
Other		15,598			9,843			40,699			36,785			24,451			13,182			44,262			25,101
Total operating revenues		357,885			207,141			890,588			903,448			622,238			291,774			1,131,613			532,703
Operating costs and expenses:
Contract drilling		111,537			59,117			291,049			309,664			196,269			100,134			372,975			179,512
Pressure pumping		134,726			63,721			313,556			234,844			191,455			102,320			348,923			178,830
Directional drilling		28,360			9,754			67,367			54,348			45,438			22,370			82,392			39,007
Other		10,444			8,665			31,079			33,775			13,738			10,409			25,822			20,635
Depreciation, depletion, amortization and impairment		141,065			157,319			437,984			517,201			121,553			144,037			238,491			296,919
Impairment of goodwill		0			0			0			395,060
Selling, general and administrative		22,063			22,355			68,176			76,692			26,079			23,555			53,540			46,113
Merger and integration expenses		918			—			2,066			—			182			1,148			2,045			1,148
Credit loss expense		0			0			0			5,606
Restructuring expenses		—			—			—			38,338
Other operating (income) expenses, net		(1,219	)		776			(3,743	)		5,980
Other operating income, net														(9,238	)		(2,789	)		(10,456	)		(2,524	)
Total operating costs and expenses		447,894			321,707			1,207,534			1,671,508			585,476			401,184			1,113,732			759,640
Operating loss		(90,009	)		(114,566	)		(316,946	)		(768,060	)
Operating income (loss)														36,762			(109,410	)		17,881			(226,937	)

Other income (expense):
Interest income		37			238			196			1,229			14			20			29			159
Interest expense, net of amount capitalized		(10,683	)		(11,288	)		(31,396	)		(33,496	)		(10,658	)		(10,704	)		(21,223	)		(20,713	)
Other		14			512			840			682			(2,452	)		812			(870	)		826
Total other expense		(10,632	)		(10,538	)		(30,360	)		(31,585	)		(13,096	)		(9,872	)		(22,064	)		(19,728	)

Loss before income taxes		(100,641	)		(125,104	)		(347,306	)		(799,645	)
Income (loss) before income taxes														23,666			(119,282	)		(4,183	)		(246,665	)

Income tax benefit		(17,643	)		(12,993	)		(54,586	)		(102,480	)
Income tax expense (benefit)														1,780			(15,973	)		2,708			(36,943	)

Net loss	$	(82,998	)	$	(112,111	)	$	(292,720	)	$	(697,165	)
Net income (loss)													$	21,886		$	(103,309	)	$	(6,891	)	$	(209,722	)

Net loss per common share:
Net income (loss) per common share:
Basic	$	(0.44	)	$	(0.60	)	$	(1.55	)	$	(3.70	)	$	0.10		$	(0.55	)	$	(0.03	)	$	(1.12	)
Diluted	$	(0.44	)	$	(0.60	)	$	(1.55	)	$	(3.70	)	$	0.10		$	(0.55	)	$	(0.03	)	$	(1.12	)

Weighted average number of common shares outstanding:
Basic		188,965			187,280			188,355			188,193			216,165			188,408			215,718			188,044
Diluted		188,965			187,280			188,355			188,193			219,676			188,408			215,718			188,044
Cash dividends per common share	$	0.02		$	0.02		$	0.06		$	0.08		$	0.04		$	0.02		$	0.08		$	0.04

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~~INCOME (LOSS)

(unaudited, in thousands)

Three Months Ended

Nine Months Ended

September 30,

September 30,

2021

2020

2021

2020

Net loss
$
(82,998
)

$
(112,111
)

$
(292,720
)

$
(697,165
)
Other comprehensive income (loss), net of taxes of $0 for all periods:

Foreign currency translation adjustment

(232
)

218

441

(473
)
Total comprehensive loss
$
(83,230
)

$
(111,893
)

$
(292,279
)

$
(697,638
)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2022			2021			2022			2021
Net income (loss)	$	21,886		$	(103,309	)	$	(6,891	)	$	(209,722	)
Other comprehensive income (loss):
Foreign currency translation adjustment, net of taxes of $0 for all periods		1,678			255			1,793			673
Release of cumulative translation adjustment, net of taxes of $3,770, into net income (loss) for three and six months ended June 30, 2022		(7,708	)		0			(7,708	)		0
Total comprehensive income (loss)	$	15,856		$	(103,054	)	$	(12,806	)	$	(209,049	)

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)


	Common Stock				Additional						Accumulated Other									Common Stock				Additional						Accumulated Other
	Number of				Paid-in			Retained			Comprehensive			Treasury						Number of				Paid-in			Retained			Comprehensive			Treasury
	Shares		Amount		Capital			Earnings			Income (Loss)			Stock			Total			Shares		Amount		Capital			Deficit			Income			Stock			Total
Balance, December 31, 2020		271,029	$	2,710	$	2,902,236		$	472,014		$	5,412		$	(1,366,313	)	$	2,016,059
Balance, December 31, 2021																					299,269	$	2,993	$	3,171,536		$	(198,316	)	$	5,915		$	(1,372,641	)	$	1,609,487
Net loss		—		—		—			(106,413	)		—			—			(106,413	)		—		—		—			(28,777	)		—			—			(28,777	)
Foreign currency translation adjustment		—		—		—			—			418			—			418			—		—		—			—			115			—			115
Vesting of restricted stock units		163		2		(2	)		—			—			—			—			150		1		(1	)		—			—			—			—
Stock-based compensation		—		—		5,891			—			—			—			5,891			—		—		4,642			—			—			—			4,642
Payment of cash dividends ($0.02 per share)		—		—		—			(3,754	)		—			—			(3,754	)
Dividend equivalents		—		—		—			(55	)		—			—			(55	)
Balance, March 31, 2021		271,192	$	2,712	$	2,908,125		$	361,792		$	5,830		$	(1,366,313	)	$	1,912,146
Net loss		—		—		—			(103,309	)		—			—			(103,309	)
Foreign currency translation adjustment		—		—		—			—			255			—			255
Vesting of restricted stock units		1,643		16		(16	)		—			—			—			—
Stock-based compensation		—		—		5,934			—			—			—			5,934
Payment of cash dividends ($0.02 per share)		—		—		—			(3,769	)		—			—			(3,769	)
Payment of cash dividends ($0.04 per share)																					—		—		—			(8,611	)		—			—			(8,611	)
Dividend equivalents		—		—		—			(18	)		—			—			(18	)		—		—		—			(144	)		—			—			(144	)
Purchase of treasury stock		—		—		—			—			—			(3,522	)		(3,522	)		—		—		—			—			—			(13	)		(13	)
Balance, June 30, 2021		272,835	$	2,728	$	2,914,043		$	254,696		$	6,085		$	(1,369,835	)	$	1,807,717
Net loss		—		—		—			(82,998	)		—			—			(82,998	)
Balance, March 31, 2022																					299,419	$	2,994	$	3,176,177		$	(235,848	)	$	6,030		$	(1,372,654	)	$	1,576,699
Net income																					—		—		—			21,886			—			—			21,886
Foreign currency translation adjustment		—		—		—			—			(232	)		—			(232	)		—		—		—			—			1,678			—			1,678
Release of cumulative translation adjustment																					—		—		—			—			(7,708	)		—			(7,708	)
Issuance of restricted stock																					980		10		(10	)		—			—			—			—
Vesting of restricted stock units		51		1		(1	)		—			—			—			—			1,287		13		(13	)		—			—			—			—
Exercise of stock options																					640		6		10,362			—			—			—			10,368
Stock-based compensation		—		—		5,048			—			—			—			5,048			—		—		5,162			—			—			—			5,162
Payment of cash dividends ($0.02 per share)		—		—		—			(3,780	)		—			—			(3,780	)
Payment of cash dividends ($0.04 per share)																					—		—		—			(8,652	)		—			—			(8,652	)
Dividend equivalents		—		—		—			(58	)		—			—			(58	)		—		—		—			(100	)		—			—			(100	)
Purchase of treasury stock		—		—		—			—			—			(52	)		(52	)		—		—		—			—			—			(23,252	)		(23,252	)
Balance, September 30, 2021		272,886	$	2,729	$	2,919,090		$	167,860		$	5,853		$	(1,369,887	)	$	1,725,645
Balance, June 30, 2022																					302,326	$	3,023	$	3,191,678		$	(222,714	)	$	0		$	(1,395,906	)	$	1,576,081


	Common Stock				Additional						Accumulated Other									Common Stock				Additional						Accumulated Other
	Number of				Paid-in			Retained			Comprehensive			Treasury						Number of				Paid-in			Retained			Comprehensive		Treasury
	Shares		Amount		Capital			Earnings			Income (Loss)			Stock			Total			Shares		Amount		Capital			Earnings			Income		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 ($0.04 per share)		—		—		—			(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
Balance, December 31, 2020																					271,029	$	2,710	$	2,902,236		$	472,014		$	5,412	$	(1,366,313	)	$	2,016,059
Net loss		—		—		—			(150,332	)		—			—			(150,332	)		—		—		—			(106,413	)		—		—			(106,413	)
Foreign currency translation adjustment		—		—		—			—			695			—			695			—		—		—			—			418		—			418
Vesting of restricted stock units		1,046		11		(11	)		—			—			—			—			163		2		(2	)		—			—		—			—
Stock-based compensation		—		—		4,335			—			—			—			4,335			—		—		5,891			—			—		—			5,891
Payment of cash dividends ($0.02 per share)		—		—		—			(3,735	)		—			—			(3,735	)		—		—		—			(3,754	)		—		—			(3,754	)
Dividend equivalents		—		—		—			(73	)		—			—			(73	)		—		—		—			(55	)		—		—			(55	)
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
Balance, March 31, 2021																					271,192	$	2,712	$	2,908,125		$	361,792		$	5,830	$	(1,366,313	)	$	1,912,146
Net loss		—		—		—			(112,111	)		—			—			(112,111	)		—		—		—			(103,309	)		—		—			(103,309	)
Foreign currency translation adjustment		—		—		—			—			218			—			218			—		—		—			—			255		—			255
Issuance of restricted stock																					621		6		(6	)		—			—		—			—
Vesting of restricted stock units		292		2		(2	)		—			—			—			—			1,022		10		(10	)		—			—		—			—
Stock-based compensation		—		—		6,592			—			—			—			6,592			—		—		5,934			—			—		—			5,934
Payment of cash dividends ($0.02 per share)		—		—		—			(3,746	)		—			—			(3,746	)		—		—		—			(3,769	)		—		—			(3,769	)
Dividend equivalents		—		—		—			(69	)		—			—			(69	)		—		—		—			(18	)		—		—			(18	)
Purchase of treasury stock		—		—		—			—			—			(194	)		(194	)		—		—		—			—			—		(3,522	)		(3,522	)
Balance, September 30, 2020	$	270,861	$	2,708	$	2,895,753		$	582,360		$	5,005		$	(1,366,263	)	$	2,119,563
Balance, June 30, 2021																					272,835	$	2,728	$	2,914,043		$	254,696		$	6,085	$	(1,369,835	)	$	1,807,717

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						Six Months Ended
	September 30,						June 30,
	2021			2020			2022			2021
Cash flows from operating activities:
Net loss	$	(292,720	)	$	(697,165	)	$	(6,891	)	$	(209,722	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, amortization and impairment		437,984			517,201			238,491			296,919
Impairment of goodwill		0			395,060
Dry holes and abandonments		177			1,256			118			171
Deferred income tax benefit		(54,754	)		(100,212	)
Deferred income tax expense (benefit)								404			(37,073	)
Stock-based compensation expense		16,873			20,087			9,804			11,825
Net gain on asset disposals		(5,595	)		(3,357	)		(10,408	)		(4,052	)
Net gain on insurance reimbursement		0			(4,172	)
Writedown of capacity reservation contract		0			9,207
Credit loss expense		0			5,606
Restructuring expenses, non-cash		0			24,068
Amortization of debt discount and issuance costs		620			673			416			412
Changes in operating assets and liabilities:
Accounts receivable		(103,241	)		202,733			(116,859	)		(36,438	)
Income taxes receivable/payable		4,378			1,285			542			4,369
Inventory and other assets		1,486			22,250			(17,671	)		(6,423	)
Accounts payable		59,357			(57,788	)		42,661			34,465
Accrued liabilities		(8,009	)		(44,607	)		(49,487	)		(8,785	)
Other liabilities		(4,958	)		(8,840	)		(6,103	)		(1,471	)
Net cash provided by operating activities		51,598			283,285			85,017			44,197

Cash flows from investing activities:
Purchases of property and equipment		(90,837	)		(135,043	)		(191,198	)		(56,573	)
Proceeds from disposal of assets and insurance claims		20,558			17,792
Proceeds from disposal of assets								15,346			15,145
Other		(345	)		(121	)		(2,342	)		(223	)
Net cash used in investing activities		(70,624	)		(117,372	)		(178,194	)		(41,651	)

Cash flows from financing activities:
Purchases of treasury stock		(3,574	)		(21,129	)		(12,897	)		(3,522	)
Dividends paid		(11,303	)		(15,110	)		(17,263	)		(7,523	)
Debt issuance costs		0			(145	)
Proceeds from borrowings under revolving credit facility								45,000			0
Repayment of borrowings under revolving credit facility								(20,000	)		0
Net cash used in financing activities		(14,877	)		(36,384	)		(5,160	)		(11,045	)
Effect of foreign exchange rate changes on cash		272			27			449			266
Net increase (decrease) in cash and cash equivalents		(33,631	)		129,556
Net decrease in cash and cash equivalents								(97,888	)		(8,233	)
Cash and cash equivalents at beginning of period		224,915			174,185			117,524			224,915
Cash and cash equivalents at end of period	$	191,284		$	303,741		$	19,636		$	216,682

Supplemental disclosure of cash flow information:
Net cash received (paid) during the period for:
Interest, net of capitalized interest of $117 in 2021 and $425 in 2020	$	(31,031	)	$	(32,605	)
Interest, net of capitalized interest of $400 in 2022 and $56 in 2021							$	(20,341	)	$	(20,604	)
Income taxes		4,196			3,550			(880	)		4,226
Non-cash investing and financing activities:
Net increase (decrease) in payables for purchases of property and equipment	$	14,801		$	(38,312	)	$	19,779		$	(5,232	)
Net (increase) decrease in deposits on equipment purchases		(66	)		3,338			(4,363	)		117
Cashless exercise of stock options								10,368			0

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 U.S. dollar is the functional currency for all of our 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, ~~2020,~~2021, 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, ~~2020.~~2021. The results of operations for the three and ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 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 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 3.

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.

In December 2019, the FASB issued an accounting standards update to simplify the accounting for income taxes. The amendments in the update ~~are~~were effective for public business entities for fiscal years beginning after December 15, 2020, with early adoption permitted. We adopted this new guidance on January 1, 2021, and there was no material impact on our consolidated financial statements.

Recently Issued Accounting Standards — 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 we do not expect this new guidance will have a material impact on our consolidated financial statements.

In October 2021, the FASB issued an accounting standards update, which requires contract assets and contract liabilities (i.e., deferred revenue) acquired in a business combination to be recognized and measured by the acquirer on the acquisition date in accordance with ASC 606, Revenue from Contracts with Customers. Generally, this new guidance will result in the acquirer recognizing contract assets and contract liabilities at the same amounts recorded by the acquiree. Historically, such amounts were recognized by the acquirer at fair value in acquisition accounting. The amendments should be applied prospectively to acquisitions occurring on or after the effective date. The amendments in the update are effective for public business entities for fiscal years beginning after December 15, 2022, with early adoption permitted. We plan to adopt this new guidance on January 1, 2023, and we do not expect this new guidance will have a material impact on our consolidated financial statements.

2. Acquisition and Discontinued Operations

Pioneer Energy Services Corp. ("Pioneer")

On October 1, 2021, we completed the acquisition of Pioneer ~~Energy Services Corp. ("Pioneer").~~by acquiring 100% of its equity interests. Total consideration for the acquisition included the issuance of approximately 26.3 million shares of our common stock and payment of $30 million cash, which based on the closing price of our common stock of $9.44 on October 1, 2021, valued the transaction at approximately $278 ~~million, including the retirement of all Pioneer’s debt.~~million.

~~In connection with the closing, Pioneer’s senior notes were repaid with cash and a portion of the shares of Patterson-UTI common stock issued in the acquisition. Pioneer shareholders received~~ ~~1.8692~~ ~~shares of Patterson-UTI common stock for each share of Pioneer common stock.~~

Pioneer provided land-based contract drilling services and production services to a diverse group of oil and gas exploration and production companies in the United States and internationally in Colombia. ~~Through the Pioneer acquisition, we acquired Pioneer’s~~ ~~100% pad-capable drilling rig fleet, with~~ 17 ~~AC rigs in the United States and~~ 8 ~~SCR rigs in Colombia, and~~ ~~production services assets consisting of~~ ~~123~~ ~~well servicing rigs and~~ 72 ~~wireline services units. We believe the~~ ~~acquisition of Pioneer enhances our position as a leading provider of contract drilling services in the United States and expands our geographic footprint into Latin America.~~

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

~~We are~~

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


Shares of our common stock issued to Pioneer shareholders		26,274
Our common stock price on October 1, 2021	$	9.44
Fair value of common stock issued	$	248,025
Plus cash consideration	$	30,007
Total fair value of consideration transferred	$	278,032

A discounted cash flow model was used by a third-party specialist in ~~the process of~~ determining the fair ~~values~~value of the property and equipment and intangible assets. We applied significant judgment in estimating the fair value of assets acquired and liabilities assumed, which involved the use of significant estimates and assumptions with respect to market day rates, direct operating costs, rig utilization percentages, expectations regarding the amount of future capital and operating costs, and discount rates. Certain data necessary to complete the purchase price allocation is not yet available, including final tax returns that provide the underlying tax basis of Pioneer's assets and liabilities. We expect to complete the purchase price allocation during the 12-month period following the acquisition date.


Identifiable assets acquired
Cash and cash equivalents	$	649
Accounts receivable		44,832
Inventory		8,513
Held for sale assets		73,649
Other current assets		5,272
Property and equipment		217,536
Other long-term assets		9,698
Intangible assets		907
Total identifiable assets acquired		361,056
Liabilities assumed
Accounts payable and accrued liabilities		30,391
Held for sale liabilities		32,160
Deferred income taxes		15,543
Other long-term liabilities		4,930
Total liabilities assumed		83,024
Total net assets acquired	$	278,032

Approximately $41.5 million of revenues and $30.5 million of direct operating expenses attributed to the Pioneer acquisition were included in the consolidated statements of operations for the period from the closing date on October 1, 2021 through December 31, 2021, excluding the acquired well servicing rig business and the wireline business that were presented as a discontinued operation in the consolidated statements of operations during the fourth quarter of 2021. Revenues and direct operating expenses for our discontinued operations are presented below.

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


	Fair Value		Weighted Average Useful Life
	(in thousands)		(in years)
Assets
Trade name	$	907		5.00

Discontinued Operations

On December 31, 2021, we completed the sale of the previously acquired well servicing rig business and wireline business (collectively, “Pioneer Production Services”), to Clearwell Dynamics, LLC (“Clearwell”). The sale price was $43.0 million in cash consideration, subject to customary purchase price adjustments at closing for cash and working capital. The results of operations ~~for~~of these ~~acquired~~ businesses ~~will be~~were presented as a discontinued operation in the consolidated financial statements during the fourth quarter of 2021.

Summarized operating results from discontinued operations that were included in our consolidated ~~results~~statements of operations ~~beginning in~~for the ~~quarter ending~~year ended December 31, ~~2021.~~2021 are shown below (in thousands):


	2021
Operating revenues:
Wireline revenue	$	9,868
Well servicing revenue		19,652
Total operating revenues		29,520

Operating costs and expenses:
Wireline		10,465
Well servicing		16,585
Total operating costs and expenses		27,050
Operating income		2,470

Total other income (expense)		64

Income from discontinued operations before income taxes		2,534

Income tax benefit		0

Income from discontinued operations, net of tax	$	2,534

3. ~~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 and nine months ended September 30, 2021.

~~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.~~

~~There was~~ 0 ~~credit loss expense during the three and nine months ended September 30, 2021~~.

4. 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 ~~15.~~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. Lease income recognized during the six months ended June 30, 2022 and 2021 was not material.

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 ~~$259~~$466 million and $~~158~~352 million as of ~~September~~June 30, ~~2021~~2022 and December 31, ~~2020,~~2021, 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. 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~~six months ended ~~September~~June 30, 2022 and 2021, 0 such mobilization payments were amortized and recorded in drilling revenue. ~~During the nine months ended September 30, 2020, approximately $0.1~~ ~~million was amortized and recorded in drilling revenue.~~

Total contract liability balances were $~~0.9~~3.4 million and $~~0.6~~60.3 million as of ~~September~~June 30, ~~2021~~2022 and December 31, ~~2020,~~2021, respectively. ~~Contract liability balances are~~We recognized $59.7 million of revenue in the six months ended June 30, 2022 that was included in ~~“Accounts payable” and~~the contract liability balance at the beginning of the period. Revenue related to the majority of our contract liabilities balance is expected to be recognized over the remainder of 2022. The contract liability balance is included in “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.

Remaining Performance Obligations

~~Recognition~~

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 in the United States as of June 30, 2022 was approximately $440 million. Approximately 24% of the total contract drilling backlog in the United States at June 30, 2022 is reasonably expected to remain at June 30, 2023. We generally calculate our backlog by multiplying the dayrate under our term drilling contracts by the number of days remaining under the contract. The calculation does not include any revenues related to fees for other services such as for mobilization, other than initial mobilization, demobilization and customer reimbursables, nor does it include potential reductions in rates for unscheduled standby or during periods in which the rig is moving or incurring maintenance and repair time in excess of what is permitted under the drilling contract. For contracts that contain variable dayrate pricing, our backlog calculation uses the dayrate in effect for periods where the dayrate is fixed, and, for periods that remain subject to variable pricing, uses the commodity price in effect at June 30, 2022. 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. Please see “Our Current Backlog of Contract Drilling Revenue ~~from Performance Obligations Satisfied~~May Decline and May Not Ultimately Be Realized, as Fixed-Term Contracts May in ~~a Prior Period~~Certain

Instances Be Terminated Without an Early Termination Payment” included in Item 1A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2021.

4. Inventory

~~During the nine months ended September 30, 2021, we recorded revenue of $2.3~~ ~~million associated with early termination revenue to which we were contractually entitled from one of our customers. While the performance obligations were satisfied during 2020, we did~~ ~~not~~ record the related revenue due to our doubts about the customer’s ability and intent to pay substantially all of the consideration to which we were entitled in accordance with ASC Topic 606. Those doubts were resolved during the three months ended March 31, 2021, when collectability became probable from the counterparty in connection with its emergence from bankruptcy. In April 2021, we received consideration from the counterparty, which validated the accuracy and collectability of the revenue recorded in the first quarter of 2021.

~~5. Inventory~~

Inventory consisted of the following at ~~September~~June 30, ~~2021~~2022 and December 31, ~~2020~~2021 (in thousands):

September 30, 2021

December 31, 2020

Finished goods
$
566

$
600

Work-in-process

943

802

Raw materials and supplies

33,415

31,683

Inventory
$
34,924

$
33,085


	June 30, 2022		December 31, 2021
Finished goods	$	817	$	515
Work-in-process		1,838		882
Raw materials and supplies		50,873		40,962
Inventory	$	53,528	$	42,359

6.5. Property and Equipment

Property and equipment consisted of the following at ~~September~~June 30, ~~2021~~2022 and December 31, ~~2020~~2021 (in thousands):


	September 30, 2021			December 31, 2020			June 30, 2022			December 31, 2021
Equipment	$	7,559,061		$	7,647,451		$	7,490,085		$	7,742,101
Oil and natural gas properties		229,224			222,738			235,925			229,403
Buildings		182,113			193,503			183,686			182,280
Land		24,562			25,781			24,861			24,562
Total property and equipment		7,994,960			8,089,473			7,934,557			8,178,346
Less accumulated depreciation, depletion and impairment		(5,570,235	)		(5,328,432	)		(5,645,186	)		(5,846,591	)
Property and equipment, net	$	2,424,725		$	2,761,041		$	2,289,371		$	2,331,755

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. We had 0 impairment related to the marketability or condition of our drilling rigs during the three and ~~nine~~six months ended ~~September~~June 30, ~~2021.~~2022.

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.

~~7. Goodwill and~~6. Intangible Assets

~~Goodwill~~ ~~— As a result of a triggering event in the first quarter of 2020, we fully impaired our remaining goodwill balance, and as a result, we had~~ 0 goodwill balance as of September 30, 2021. At times when we have a goodwill balance, we are required to evaluate goodwill 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 assumptions included discount rates, revenue growth rates, operating expense growth rates, and terminal growth rates.

~~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~~June 30, ~~2021~~2022 and December 31, ~~2020~~2021 (in thousands):


	June 30, 2022							December 31, 2021
	Gross					Net		Gross					Net
	Carrying		Accumulated			Carrying		Carrying		Accumulated			Carrying
	Amount		Amortization			Amount		Amount		Amortization			Amount
Customer relationships	$	1,800	$	(943	)	$	857	$	1,800	$	(814	)	$	986
Developed technology		7,772		(3,385	)		4,387		55,772		(50,996	)		4,776
Internal use software		1,288		(137	)		1,151		1,428		(515	)		913
Trade name		907		(136	)		771		907		(45	)		862
Intangible assets, net	$	11,767	$	(4,601	)	$	7,166	$	59,907	$	(52,370	)	$	7,537

September 30, 2021

December 31, 2020

Gross

Net

Gross

Net

Carrying

Accumulated

Carrying

Carrying

Accumulated

Carrying

Amount

Amortization

Amount

Amount

Amortization

Amount

Customer relationships
$
1,800

$
(750
)

$
1,050

$
28,000

$
(26,757
)

$
1,243

Developed technology

55,772

(36,613
)

19,159

55,772

(27,515
)

28,257

Internal use software

1,251

(408
)

843

906

(319
)

587

$
58,823

$
(37,771
)

$
21,052

$
84,678

$
(54,591
)

$
30,087

Amortization expense on intangible assets of approximately $~~3.1~~0.4 million and $~~5.3~~3.1 million was recorded in the three months ended ~~September~~June 30, ~~2021~~2022 and ~~2020,~~2021, respectively. Amortization expense on intangible assets of approximately $~~9.4~~0.7 million and $~~15.9~~6.3 million was recorded in the ~~nine~~six months ended ~~September~~June 30, 2022 and 2021, ~~and 2020,~~ respectively.

8.7. Accrued Liabilities

Accrued liabilities consisted of the following at ~~September~~June 30, ~~2021~~2022 and December 31, ~~2020~~2021 (in thousands):

September 30, 2021

December 31, 2020

Salaries, wages, payroll taxes and benefits
$
38,046

$
37,627

Workers' compensation liability

62,428

70,847

Property, sales, use and other taxes

19,572

10,666

Insurance, other than workers' compensation

7,686

8,462

Accrued interest payable

10,101

11,325

Accrued restructuring expenses

7,884

14,310

Other

21,411

21,767

Accrued liabilities
$
167,128

$
175,004


	June 30, 2022		December 31, 2021
Salaries, wages, payroll taxes and benefits	$	47,445	$	52,252
Workers' compensation liability		66,734		67,921
Property, sales, use and other taxes		14,786		9,673
Insurance, other than workers' compensation		4,437		6,494
Accrued interest payable		11,306		11,226
Accrued restructuring expenses		2,400		7,884
Customer prepayment		3,409		60,282
Other		38,686		22,779
Accrued liabilities	$	189,203	$	238,511

9.8. Long-Term Debt

Long-term debt consisted of the following at ~~September~~June 30, ~~2021~~2022 and December 31, ~~2020~~2021 (in thousands):

September 30, 2021

December 31, 2020

Term Loan Agreement (Maturing June 2022) (1)
$
50,000

$
50,000

3.95% Senior Notes

509,505

509,505

5.15% Senior Notes

349,250

349,250

908,755

908,755

Less deferred financing costs and discounts

(6,651
)

(7,271
)
Total
$
902,104

$
901,484

~~(1)~~

~~The borrowings outstanding under the Term Loan Agreement maturing in~~ ~~June 2022~~ ~~are classified as long-term because we have the ability and intent to repay these obligations utilizing our revolving credit facility.~~ ~~Our revolving credit facility matures in two increments in 2024 and 2025.~~


	June 30, 2022			December 31, 2021
Revolving credit facility	$	25,000		$	0
3.95% Senior Notes		509,505			509,505
5.15% Senior Notes		349,250			349,250
		883,755			858,755
Less deferred financing costs and discounts		(6,016	)		(6,432	)
Total	$	877,739		$	852,323

~~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 permitted a single borrowing of up to $150~~ ~~million initially, 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. We repaid $~~50 ~~million of the borrowings under the Term Loan Agreement on December 16, 2019, and an additional $~~50 ~~million on December 24, 2020. As of September 30, 2021, we had $~~50 ~~million in borrowings remaining outstanding under the Term Loan Agreement at a LIBOR-based interest rate of~~ ~~1.46%. The maturity date under the Term Loan Agreement is~~ ~~June 10, 2022. The borrowings outstanding under the Term Loan Agreement maturing in~~ ~~June 2022~~ ~~are classified as long-term because we have the ability and intent to repay these obligations utilizing our revolving credit facility.~~ ~~Our revolving credit facility matures in two increments in 2024 and 2025.~~

~~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, 2021, 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, 2021.

Credit Agreement — On March 27, 2018, we entered into an amended and restated credit agreement ~~(the~~(as amended, 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 the revolving credit commitments ~~of certain lenders~~ under the Credit Agreement ~~from~~is March 27, ~~2024~~2025 to, and the maturity date for the remaining $50 million of revolving credit commitments is March 27, ~~2025~~2024. We have the option, subject to certain conditions, to exercise an 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. As of ~~September~~June 30, ~~2021, the~~2022, applicable margin on LIBOR rate loans was 1.75% and the applicable margin on base rate loans was 0.75%. 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~~June 30, ~~2021.~~2022.

As of ~~September~~June 30, ~~2021,~~2022, we had $025.0 ~~borrowings~~million outstanding under our revolving credit ~~facility.~~facility at a base rate of 5.5%. We had $0.1 million in letters of credit outstanding under the Credit Agreement at ~~September~~June 30, ~~2021~~2022 and, as a result, had available borrowing capacity of approximately $~~600~~575 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~~June 30, ~~2021,~~2022, we had $~~63.6~~65.0 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.

2028 Senior Notes and 2029 Senior Notes — 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”). ~~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 Senior Notes. The remaining net proceeds and available cash on hand was used to repay $~~50 ~~million of the borrowings under the Term Loan Agreement in 2019.~~

~~During the fourth quarter of 2020, we elected to repurchase portions of our 2028 Notes and 2029 Notes in the open market. The principal amounts retired through these transactions totaled $15.5~~ ~~million related to our 2028 Notes and $0.8~~ ~~million related to our 2029 Notes, plus accrued interest.~~

We pay interest on the 2028 Notes on February 1 and August 1 of each ~~year.~~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.~~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.

At our option, we 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, at our option, we may redeem the respective Senior Notes in whole or in part, at a redemption price equal to ~~100%~~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 — Debt issuance costs, except those related to line-of-credit arrangements, are presented in the balance sheet as a direct reduction of the carrying amount of the related debt. Debt issuance costs related to line-of-credit arrangements are included in “Other non-current assets” in the condensed consolidated balance sheets. 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 for the three months ended ~~September~~June 30, ~~2021~~2022 and ~~2020,~~2021, respectively, and $~~0.8~~0.5 million for the ~~nine~~six months ended ~~September~~June 30, 2022 and 2021, ~~and 2020,~~ respectively.

Presented below is a schedule of the principal repayment requirements of long-term debt as of ~~September~~June 30, ~~2021~~2022 (in thousands):

Year ending December 31,

2021
$
—

2022

50,000

2023

—

2024

—

2025

—

Thereafter

858,755

Total
$
908,755


Year ending December 31,
2022	$	0
2023		0
2024		0
2025		25,000
2026		0
Thereafter		858,755
Total	$	883,755

~~10.~~9. Commitments and Contingencies

As of ~~September~~June 30, ~~2021,~~2022, we maintained letters of credit in the aggregate amount of $~~63.7~~65.1 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~~June 30, ~~2021,~~2022, 0 amounts had been drawn under the letters of credit.

As of ~~September~~June 30, ~~2021,~~2022, we had commitments to purchase major equipment totaling approximately $~~58.3~~97.8 million for our contract 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 2021 and 2022~~. As of ~~September~~June 30, ~~2021,~~2022, the remaining minimum obligation under these agreements was approximately $~~9.0~~16.1 million, of which approximately $~~7.3~~4.1 million, $9.0 million, and $~~1.7~~3.0 million relate to the remainder of ~~2021~~2022, 2023, and ~~2022,~~2024, respectively.

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.

~~11.~~10. Stockholders’ Equity

~~Stockholder Rights Agreement~~ Cash Dividend— 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 entitled 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 were 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”). The Rights Agreement expired on ~~April 21, 2021~~.

On ~~October~~ July 27, ~~2021~~2022, our Board of Directors approved a cash dividend on our common stock in the amount of $~~0.02~~0.04 per share to be paid on ~~December 16, 2021~~September 15, 2022 to holders of record as of ~~December 2, 2021~~September 1, 2022. 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. Our Board of Directors may, without advance notice, reduce or suspend our dividend to improve our financial flexibility and position our company for long-term success. There can be no assurance that we will pay a dividend in the future.

Share ~~Repurchase~~Repurchases and Acquisitions — OnIn September 6, 2013, our Board of Directors approved a stock buyback program. In July 2019, our Board of Directors increased the amount authorized to be repurchased under the program ~~that authorized purchases of~~to up to $~~200~~250 million of our common stock in open market or privately negotiated transactions. The authorized repurchases under this program were subsequently increased in July 2018 and February 2019, and 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.~~stock. 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~~June 30, ~~2021,~~2022, 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.

Treasury stock acquisitions during the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 were as follows (dollars in thousands):

Shares

Cost

Treasury shares at beginning of period

83,402,322

$
1,366,313

Acquisitions pursuant to long-term incentive plan

434,224

3,574

Treasury shares at end of period

83,836,546

$
1,369,887


	Shares		Cost
Treasury shares at January 1, 2022		84,128,995	$	1,372,641
Acquisitions pursuant to long-term incentive plan		1,372,101		23,237
Other		3,027		28
Treasury shares at June 30, 2022		85,504,123	$	1,395,906

Release of Cumulative Translation Adjustment — In April 2022, we sold certain assets to substantially complete our exit from our Canadian operations. We used the Canadian dollar as our functional currency for our Canadian operations. Prior to the substantial completion of our exit, the effects of exchange rate changes were reflected in accumulated other comprehensive income, which is a separate component of stockholders' equity. Upon substantial completion of our exit, we released the $7.7 million cumulative translation adjustment, net of tax of $3.8 million, from accumulated other comprehensive income into net income (loss) for the three and six months ended June 30, 2022. The release resulted in an $11.5 million pre-tax gain, which was recorded in other operating (income) expenses, net.

~~12.~~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. Outstanding share-based awards include equity instruments in the form of stock options 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.

On April 9, 2021, subject to the approval of our stockholders, our Board of Directors approved the Patterson-UTI Energy, Inc. 2021 Long-Term Incentive Plan (the “2021 Plan”). On June 3, 2021, our stockholders approved the 2021 Plan. The aggregate number of shares of Common Stock authorized for grant under the 2021 Plan is approximately ~~13.5~~ ~~million, which includes approximately~~ ~~4.9~~ ~~million shares previously authorized under our Amended and Restated 2014 Long-Term Incentive Plan, as amended (the “2014 Plan”).~~

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. NaN options were granted during the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 or ~~2020.~~2021.

Stock option activity from January 1, ~~2021~~2022 to ~~September~~June 30, ~~2021~~2022 follows:

Weighted

Average

Underlying

Exercise Price

Shares

Per Share

Outstanding at January 1, 2021

4,026,150

$
21.63

Exercised

—

$
—

Expired

(276,000
)

$
31.20

Outstanding at September 30, 2021

3,750,150

$
20.92

Exercisable at September 30, 2021

3,750,150

$
20.92


				Weighted
				Average
	Underlying			Exercise Price
	Shares			Per Share
Outstanding at January 1, 2022		3,720,150		$	20.93
Exercised		(640,000	)	$	16.20
Expired		(100,000	)	$	17.27
Outstanding at June 30, 2022		2,980,150		$	22.07
Exercisable at June 30, 2022		2,980,150		$	22.07

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, ~~2021~~2022 to ~~September~~June 30, ~~2021~~2022 follows:


						Weighted							Weighted
						Average Grant							Average Grant
	Time			Performance		Date Fair Value		Time			Performance		Date Fair Value
	Based			Based		Per Share		Based			Based		Per Share
Non-vested restricted stock units outstanding at January 1, 2021		2,741,548			359,315	$	9.52
Non-vested restricted stock units outstanding at January 1, 2022									3,044,719			359,315	$	8.31
Granted		1,797,875			—	$	8.32		1,554,849			0	$	17.37
Vested		(1,235,616	)		—	$	10.44		(1,437,286	)		0	$	7.32
Forfeited		(109,399	)		—	$	10.88		(34,365	)		0	$	12.75
Non-vested restricted stock units outstanding at September 30, 2021		3,194,408			359,315	$	8.55
Non-vested restricted stock units outstanding at June 30, 2022									3,127,917			359,315	$	12.71

As of ~~September~~June 30, ~~2021,~~2022, we had unrecognized compensation cost related to our unvested restricted stock units totaling $~~20.9~~34.2 million. The weighted-average remaining vesting period for these unvested restricted stock units was ~~1.84~~1.90 years.

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 ~~usually~~generally the three-year period commencing on April 1 of the year of grant.

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. For the performance units granted in April 2022 and April 2021, the peer group ~~also~~ includes one market index and three market ~~indices. These~~indices, respectively. The performance 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. ~~Under~~For the Performance Units granted beginning in April 2019, 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 55th55th percentile. If our total shareholder return during the performance period, when compared to the peer group, is at the 75th75th 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 25th25th 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 25th25th and 55th55th percentile, or the 55th55th and 75th75th percentile, then the shares to be received by the recipients will be determined using linear interpolation for levels of achievement between these points.

~~Under~~For the Performance Units granted beginning in April 2019, 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.~~performance period.

The total target number of shares with respect to the Performance Units for the awards granted in ~~2017-2021~~2018-2022 is set forth below:

2021

2020

2019

2018

2017

Performance

Performance

Performance

Performance

Performance

Unit Awards

Unit Awards

Unit Awards

Unit Awards

Unit Awards

Target number of shares

843,000

500,500

489,800

310,700

186,198


	2022		2021		2020		2019		2018
	Performance		Performance		Performance		Performance		Performance
	Unit Awards		Unit Awards		Unit Awards		Unit Awards		Unit Awards
Target number of shares		414,000		843,000		500,500		489,800		310,700

In April 2021, 621,400 shares were issued to settle the 2018 Performance Units. In April 2022, 979,600 shares were issued to settle the 2019 Performance Units. The Performance Units granted in ~~2019,~~ 2020, 2021 and ~~2021~~2022 have not reached the end of their respective performance periods.

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):

2021

2020

2019

2018

2017

Performance

Performance

Performance

Performance

Performance

Unit Awards

Unit Awards

Unit Awards

Unit Awards

Unit Awards

Aggregate fair value at date of grant
$
7,225

$
826

$
9,958

$
8,004

$
5,780


	2022		2021		2020		2019		2018
	Performance		Performance		Performance		Performance		Performance
	Unit Awards		Unit Awards		Unit Awards		Unit Awards		Unit Awards
Aggregate fair value at date of grant	$	10,743	$	7,225	$	826	$	9,958	$	8,004

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):

2021

2020

2019

2018

2017

Performance

Performance

Performance

Performance

Performance

Unit Awards

Unit Awards

Unit Awards

Unit Awards

Unit Awards

Three months ended September 30, 2021
$
602

$
69

$
830

NA

NA

Three months ended September 30, 2020
NA

$
69

$
830

$
667

NA

Nine months ended September 30, 2021
$
1,204

$
206

$
2,489

$
667

NA

Nine months ended September 30, 2020
NA

$
138

$
2,489

$
2,001

$
642


	2022		2021		2020		2019		2018
	Performance		Performance		Performance		Performance		Performance
	Unit Awards		Unit Awards		Unit Awards		Unit Awards		Unit Awards
Three months ended June 30, 2022	$	895	$	602	$	69	NA		NA
Three months ended June 30, 2021	NA		$	602	$	69	$	830	NA
Six months ended June 30, 2022	$	895	$	1,204	$	138	$	830	NA
Six months ended June 30, 2021	NA		$	602	$	138	$	1,660	$	667

As of ~~September~~June 30, ~~2021,~~2022, we had unrecognized compensation cost related to our unvested Performance Units totaling $~~8.1~~14.3 million. The weighted-average remaining vesting period for these unvested Performance Units was 1.70 years.

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~~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,~~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 a $~~0.2~~0.5 million ~~decrease to~~and $1.0 million of compensation expense associated with the Phantom Units during the three months ended ~~September~~June 30, 2022 and 2021, ~~due to a decrease in fair value for the period,~~respectively, and ~~minimal expense during the three months ended September 30, 2020. We~~we recognized $~~1.3~~3.6 million and $~~0.2~~1.5 million of compensation expense for the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 and ~~2020,~~2021, respectively.

~~13.~~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, the realizability of deferred tax assets 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~~June 30, ~~2021~~2022 was ~~17.5~~7.5%, compared with ~~10.4~~13.4% for the three months ended ~~September~~June 30, ~~2020.~~2021. The ~~higher~~lower effective income tax rate for the three months ended ~~September~~June 30, ~~2021~~2022 was primarily attributable to the ~~non-deductible portion~~impact of valuation allowances between periods. For the ~~goodwill impairment included~~three months ended June 30, 2022, due to valuation allowances, only certain income tax expense related to Colombia and certain U.S. states was recorded, resulting in ~~the 2020 estimated annual~~a lower overall effective ~~tax rate. This was partially offset by the valuation allowance included in the 2021 estimated annual effective~~income tax rate.

Our effective income tax rate for the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 was (~~15.7~~64.7)%, compared with ~~12.8~~15.0% for the ~~nine~~six months ended ~~September~~June 30, ~~2020.~~2021. The ~~higher~~lower effective income tax rate for the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 was primarily attributable to the ~~non-deductible portion~~impact of valuation allowances between periods. For the ~~goodwill impairment included~~period ending June 30, 2022, due to valuation allowances, only certain income tax expense related to Colombia and certain U.S. states was recorded during a period with a pre-tax loss. This resulted in ~~the 2020 estimated annual~~a negative effective ~~tax rate. This was partially offset by the valuation allowance included in the 2021 estimated annual effective~~income tax rate ~~and also state rate changes enacted during 2021.~~for the six months ended June 30, 2022.

deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. We assess the realizability of our deferred tax assets quarterly and consider carryback availability, the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. In the ~~third quarter~~first two quarters of ~~2021,~~2022, the effective tax rate takes into consideration the estimated valuation allowance based on forecasted ~~2021~~2022 income.

We continue to monitor income tax developments in the United States and other countries where we have legal entities. During the first quarter of 2021, the United States enacted the American Rescue Plan of 2021, which contains various tax provisions. As a result of this legislation, we have considered these tax provisions and do not expect any material impacts 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.

~~14.~~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.~~period.

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 non-vested restricted stock units is determined using the treasury stock method.

The following table presents information necessary to calculate net loss per share for the three and ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 and ~~2020~~2021 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,

2021

2020

2021

2020

BASIC EPS:

Net loss attributed to common stockholders

(82,998
)

$
(112,111
)

(292,720
)
$
(697,165
)
Weighted average number of common shares outstanding, excluding
non-vested shares of restricted stock

188,965

187,280

188,355

188,193

Basic net loss per common share
$
(0.44
)

$
(0.60
)

$
(1.55
)
$
(3.70
)
DILUTED EPS:

Net loss attributed to common stockholders

(82,998
)

$
(112,111
)

(292,720
)
$
(697,165
)
Weighted average number of common shares outstanding, excluding
non-vested shares of restricted stock

188,965

187,280

188,355

188,193

Add dilutive effect of potential common shares

0

0

0

0

Weighted average number of diluted common shares outstanding

188,965

187,280

188,355

188,193

Diluted net loss per common share
$
(0.44
)

$
(0.60
)

$
(1.55
)
$
(3.70
)
Potentially dilutive securities excluded as anti-dilutive

9,334

8,490

9,334

8,490


	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2022		2021			2022			2021
BASIC EPS:
Net income (loss) attributed to common stockholders	$	21,886	$	(103,309	)	$	(6,891	)	$	(209,722	)
Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock		216,165		188,408			215,718			188,044
Basic net income (loss) per common share	$	0.10	$	(0.55	)	$	(0.03	)	$	(1.12	)
DILUTED EPS:
Net income (loss) attributed to common stockholders	$	21,886	$	(103,309	)	$	(6,891	)	$	(209,722	)
Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock		216,165		188,408			215,718			188,044
Add dilutive effect of potential common shares		3,511		0			0			0
Weighted average number of diluted common shares outstanding		219,676		188,408			215,718			188,044
Diluted net income (loss) per common share	$	0.10	$	(0.55	)	$	(0.03	)	$	(1.12	)
Potentially dilutive securities excluded as anti-dilutive		3,683		10,361			9,982			10,361

~~15.~~14. Business Segments

At ~~September~~June 30, ~~2021,~~2022, we had 3 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.

2019

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


	Three Months Ended						Nine Months Ended						Three Months Ended						Six Months Ended
	September 30,						September 30,						June 30,						June 30,
	2021			2020			2021			2020			2022			2021			2022			2021
Revenues:
Contract drilling	$	158,154		$	115,105		$	434,080		$	554,421		$	307,618		$	142,264		$	567,301		$	275,926
Pressure pumping		152,634			71,973			340,464			256,613			238,376			111,991			427,966			187,830
Directional drilling		31,728			10,271			76,267			56,498			54,825			24,869			98,159			44,539
Other operations (1)		20,744			11,756			53,561			46,061			29,233			18,251			54,259			32,817
Elimination of intercompany revenues - Contract drilling (2)		(229	)		(51	)		(922	)		(869	)		(3,032	)		(532	)		(6,075	)		(693	)
Elimination of intercompany revenues - Other operations (2)		(5,146	)		(1,913	)		(12,862	)		(9,276	)		(4,782	)		(5,069	)		(9,997	)		(7,716	)
Total revenues	$	357,885		$	207,141		$	890,588		$	903,448		$	622,238		$	291,774		$	1,131,613		$	532,703

Income (loss) before income taxes:
Contract drilling	$	(51,830	)	$	(47,214	)	$	(158,680	)	$	(481,974	)	$	21,720		$	(58,229	)	$	18,556		$	(106,850	)
Pressure pumping		(13,774	)		(30,856	)		(77,434	)		(134,896	)		20,091			(23,921	)		26,512			(63,660	)
Directional drilling		(4,581	)		(9,912	)		(14,614	)		(34,892	)		4,028			(5,110	)		5,816			(10,033	)
Other operations		(1,335	)		(6,421	)		(9,178	)		(35,547	)		3,300			(3,287	)		4,041			(7,843	)
Corporate		(18,489	)		(20,163	)		(57,040	)		(75,145	)		(12,377	)		(18,863	)		(37,044	)		(38,551	)
Credit loss expense		—			—			—			(5,606	)
Interest income		37			238			196			1,229			14			20			29			159
Interest expense		(10,683	)		(11,288	)		(31,396	)		(33,496	)		(10,658	)		(10,704	)		(21,223	)		(20,713	)
Other		14			512			840			682			(2,452	)		812			(870	)		826
Loss before income taxes	$	(100,641	)	$	(125,104	)	$	(347,306	)	$	(799,645	)
Income (loss) before income taxes													$	23,666		$	(119,282	)	$	(4,183	)	$	(246,665	)

Depreciation, depletion, amortization and impairment:
Contract drilling	$	97,160		$	102,275		$	297,426		$	328,843		$	84,905		$	98,592		$	166,928		$	200,266
Pressure pumping		29,838			37,104			98,963			118,586			24,713			31,740			48,498			69,125
Directional drilling		6,772			9,600			19,863			29,698			3,859			6,594			7,203			13,091
Other operations		5,866			6,852			17,309			35,087			6,803			5,619			13,200			11,443
Corporate		1,429			1,488			4,423			4,987			1,273			1,492			2,662			2,994
Total depreciation, depletion, amortization and impairment	$	141,065		$	157,319		$	437,984		$	517,201		$	121,553		$	144,037		$	238,491		$	296,919

Capital expenditures:
Contract drilling	$	21,239		$	9,502		$	56,708		$	101,448		$	50,165		$	24,042		$	101,875		$	35,469
Pressure pumping		6,468			1,653			19,457			17,880			34,554			8,921			68,016			12,989
Directional drilling		3,290			510			4,613			4,562			4,036			1,219			7,002			1,323
Other operations		2,833			1,704			9,006			9,776			7,189			3,429			13,391			6,173
Corporate		434			73			1,053			1,377			426			439			914			619
Total capital expenditures	$	34,264		$	13,442		$	90,837		$	135,043		$	96,370		$	38,050		$	191,198		$	56,573


	September 30, 2021		December 31, 2020		June 30, 2022		December 31, 2021
Identifiable assets:
Contract drilling	$	2,099,859	$	2,315,318	$	2,177,484	$	2,169,501
Pressure pumping		474,013		486,702		522,016		458,202
Directional drilling		105,368		107,807		105,468		87,285
Other operations		85,713		88,676		99,154		85,932
Corporate (3)		252,510		300,566		55,855		156,928
Total assets	$	3,017,463	$	3,299,069	$	2,959,977	$	2,957,848

(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.

~~16.~~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~~June 30, ~~2021~~2022 and December 31, ~~2020~~2021 is set forth below (in thousands):


	September 30, 2021				December 31, 2020				June 30, 2022				December 31, 2021
	Carrying		Fair		Carrying		Fair		Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value		Value		Value		Value		Value
Term Loan Agreement	$	50,000	$	50,000	$	50,000	$	50,000
Revolving credit facility									$	25,000	$	25,000	$	0	$	0
3.95% Senior Notes		509,505		513,367		509,505		471,019		509,505		432,972		509,505		511,652
5.15% Senior Notes		349,250		360,443		349,250		319,560		349,250		301,773		349,250		359,142
Total debt	$	908,755	$	923,810	$	908,755	$	840,579	$	883,755	$	759,745	$	858,755	$	870,794

The carrying value of the balance outstanding under the revolving credit facility approximates its fair value as this instrument has floating interest rates. The fair values of the 3.95% Senior Notes ~~at September 30, 2021~~ and ~~December 31, 2020 are based on discounted cash flows associated with the notes using the~~ ~~3.81% market rate of interest at September 30, 2021 and the~~ ~~5.24% market rate of interest at December 31, 2020. The fair values of~~ the 5.15% Senior Notes at ~~September~~June 30, ~~2021~~2022 and December 31, ~~2020~~2021 are based on ~~discounted cash flows associated with the notes using the~~ ~~4.67~~%quoted market ~~rate of interest at September 30, 2021 and the~~ ~~6.42% market rate of interest at December 31, 2020. The fair value estimates of the 3.95% Senior Notesand the 5.15% Senior Notes~~prices, which are considered Level 1 fair value estimates in the fair value hierarchy of fair value accounting. The ~~carrying~~fair values of the ~~balance outstanding~~3.95% Senior Notes implied a 7.27% market rate of interest at ~~September~~June 30, 2022 and a 3.87% market rate of interest at December 31, 2021, ~~under~~based on their quoted market prices. The fair values of the ~~Term Loan Agreement approximated its fair value as the instrument has~~5.15% Senior Notes implied a ~~floating~~7.59% market rate of interest ~~rate.~~at June 30, 2022 and a 4.72% market rate of interest at December 31, 2021, based on their quoted market prices.

~~17. Restructuring Expenses~~

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. We completed the restructuring plan during the third quarter of 2020 and did not incur additional expenses related to the plan.~~

~~Contract termination costs related primarily to agreements to purchase minimum quantities of proppants (sand) from certain vendors. These costs were primarily comprised of a $5.3~~ ~~million negotiated settlement and termination of a contract to purchase minimum quantities of sand and $14.0~~ million of contractual future payments under two 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 related primarily to facility closure costs and moving expenses.

~~The right of use (“ROU”) asset abandonments related 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

2221

SPECIAL NOTE REGARDING ~~FORWARD LOOKING~~FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (this “Report”) and other public filings, press releases and presentations 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, cost and margin expectations and backlog; financing of operations; oil and natural gas prices; rig counts and frac spreads; source and sufficiency of funds required for building new equipment, upgrading existing equipment and acquisitions (if opportunities arise); demand and pricing for our services; competition; equipment availability; government regulation; legal proceedings; debt service obligations; impact of inflation; 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 relate to:



the ultimate timing, outcome and results of integrating the operations of Pioneer Energy Services Corp. (“Pioneer”) into our Company, including the risk that Pioneer’s businesses may not be integrated successfully;



~~the effects of the acquisition on us, including our future financial condition, results of operations, strategy and plans;~~



~~potential adverse reactions or changes to business or employee relationships resulting from the closing of the transaction;~~



~~the failure to realize expected synergies and other benefits from the transaction in the timeframe expected or at all;~~

•

adverse oil and natural gas industry conditions, including ~~the rapid decline in crude oil prices~~ as a result of economic repercussions from the 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;

•

the impact of the ongoing conflict in Ukraine;

•

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;

•

the ability to retain management and field personnel;

•

loss of key customers;

•

inflationary pressure on labor and supplies;

•

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

•

cybersecurity events;

•

synergies, costs and financial and operating impacts of acquisitions;

•

potential adverse reactions or changes to business or employee relationships resulting from the acquisition;

•

the failure to realize expected synergies and other benefits from the acquisition in the timeframe expected or at all;

•

difficulty in building and deploying new equipment;

•

governmental regulation;

•

climate legislation, regulation and other related risks;

•

environmental, social and governance practices, including the perception thereof;

•

environmental risks and ability to satisfy future environmental costs;

•

technology-related disputes;

•

legal proceedings and actions by governmental or other regulatory agencies;

•

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 SEC.

We caution that the foregoing list of factors is not exhaustive. Additional information concerning these and other risk factors is contained elsewhere in this Report and in our Annual Report on Form 10-K for the year ended December 31, ~~2020~~2021 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.

2423

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

In November 2020, the U.S. Securities and Exchange Commission (the “SEC”) adopted the final rule under SEC Release No. 33-10890, Management’s Discussion and Analysis, Selected Financial Data, and Supplementary Financial Information, to modernize and simplify Management’s Discussion and Analysis and certain financial disclosure requirements. The final rule became effective on February 10, 2021 and must be applied in a registrant’s first fiscal year ending on or after August 9, 2021. Under the amendments to Item 303 of Regulation S-K contained in SEC Release No. 33-10890, we have the option, in discussing any material changes in our results of operations with respect to either the most recent quarter for which a statement of comprehensive income (loss) is provided and the corresponding quarter for the preceding fiscal year or, in the alternative, the most recent quarter for which a statement of comprehensive income is provided and the immediately preceding sequential quarter. We have elected the latter alternative, as management believes that comparing current quarter results to those of the immediately preceding quarter is more useful in identifying current business trends and provides a more meaningful comparison.

Management Overview and Recent Developments in Market Conditions — 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 internationally in Colombia 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 directional and horizontal ~~wellbore placement.~~wellbores. 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.

~~During 2020, reduced~~Reduced demand for crude oil and refined products related to the COVID-19 pandemic ~~combined with production increases from OPEC+ early in the year,~~ led to a significant reduction in crude oil prices and demand for drilling and completion services in the United States. Although OPEC+ agreed in April 2020 to cut oil production, OPEC+ has been gradually reducing such cuts, and in July 2021 agreed to further reduce such cuts on a monthly basis with a goal of phasing out all production cuts towards the end of 2022. There is no assurance that the most recent OPEC+ agreement will be observed by its parties, and OPEC+ may change its agreement based on market conditions or other reasons.

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 ~~recovered~~early 2021. However, market fundamentals are now strong, as demand has increased for drilling and completions equipment and services, and industry supply remains constrained. We expect the strong demand for our services to ~~reach a third quarter 2021 high of $75.54 per barrel~~continue, and we anticipate further improvements in pricing and activity. The current demand for equipment and services and strong pricing environment remain dependent on ~~September 27, 2021. In~~macro conditions, including commodity prices, geopolitical environment, response to the ~~rapid decline~~COVID-19 pandemic (including any resurgences and/or lockdowns in ~~commodity~~the United States and abroad) and continued focus by exploration and production companies and service companies on capital discipline. Oil prices ~~E&P companies acted swiftly~~averaged $108.72 per barrel in the second quarter of 2022, as compared to ~~reduce drilling and completion activity starting late~~$94.45 per barrel in the first quarter of ~~2020. While oil prices~~2022.

Due to improving activity levels, supply chain disruptions and ~~demand~~increasing tightness in the overall labor market, we continue to see general oilfield cost inflation across our segments, including increases in the cost of labor, services and supplies. Supply chain disruptions and the increasing challenge of attracting and retaining employees are increasing the complexity of reactivating equipment.

Pricing for all our services ~~have recovered~~increased in ~~2021, our average number~~2022 due in part to the limited supply of ~~rigs operating remains well below the number of our~~readily available, ~~rigs,~~high-quality drilling and ~~a significant portion of our pressure pumping horsepower remains stacked. Oil prices averaged $70.58 per barrel in the third quarter of 2021.~~completion equipment.

Our average active rig count in the United States for the ~~third~~second quarter of ~~2021~~2022 was 80121 rigs. This was an increase from our average active rig count for the ~~second~~first quarter of ~~2021~~2022 of ~~73. We expect our operating rig count for the fourth quarter, including 13~~ ~~rigs from Pioneer Energy Services Corp. (“Pioneer”), to average approximately 106 rigs~~115. Based on contracts in place in the United States~~. Based on contracts currently in place,~~ as of June 30, 2022, we ~~expect~~expected an average of 5371 rigs operating under term contracts (contracts with a duration of six months or more) during the ~~fourth~~third quarter of ~~2021~~2022 and an average of 3546 rigs operating under term contracts during the twelve months ending ~~September~~June 30, ~~2022.~~2023.

We ended the ~~third~~second quarter with ~~ten~~12 active pressure pumping spreads, compared to ~~nine~~11 at the end of the ~~second quarter.~~first quarter of 2022. Our average active spread count was ~~approximately nine spreads and effective utilization was close to ten~~11 spreads for the ~~third~~second quarter. We calculated average active spreads as the average number of spreads that were crewed and actively marketed during the ~~period, and we calculated effective utilization as total pumping days during the quarter divided by 75 days, which we consider full effective utilization for a spread for the~~ period. We expect to ~~average approximately ten~~end the third quarter with 12 active ~~spreads in the fourth quarter. The~~ pressure pumping ~~market has improved but remains oversupplied.~~spreads.

Due to improving activity levels and increasing tightness in the overall labor market, we are beginning to see general oilfield cost inflation across our segments, including increases in the cost of labor, services and supplies. This inflation, combined with the increasing challenge of attracting employees to the industry, is increasing the complexity of reactivating equipment. We ~~believe this challenge, combined with the increasing market tightness for premium drilling and completion services, will support higher pricing going forward. During 2021, we~~have increased our ~~2021~~2022 capital ~~expenditure~~expenditures forecast to approximately ~~$170 million based on conversations with customers about increasing activity levels into 2022.~~

Recent Developments in Financial Matters and Merger and Acquisition Activity —On October 1, 2021, we completed the acquisition of ~~Pioneer.~~Pioneer by acquiring 100% of its equity interests. Total consideration for the acquisition included the issuance of approximately 26.3 million shares of our common stock and payment of $30 million cash, which based on the closing price of our common stock of $9.44 on October 1, 2021, valued the transaction at approximately $278 ~~million, including the retirement of all Pioneer’s debt.~~million.

2524

In connection with the closing, Pioneer’s senior notes were repaid with cash and a portion of the shares of Patterson-UTI common stock issued in the acquisition. Pioneer shareholders received 1.8692 shares of Patterson-UTI common stock for each share of Pioneer common stock.

Pioneer provided land-based contract drilling services and production services to a diverse group of oil and gas exploration and production companies in the United States and internationally in Colombia. Through the Pioneer acquisition, we acquired Pioneer’s 100% pad-capable drilling rig fleet ~~with~~consisting of 17 ACAC-powered rigs in the United States and eight SCR rigs in Colombia and production services assets consisting of 123 well servicing rigs and 72 wireline services units. ~~We believe the~~ ~~acquisition of Pioneer enhances our position as a leading provider of contract drilling services in the United States and expands our geographic footprint into Latin America.~~

~~We are in~~On December 31, 2021, we completed the ~~process of determining the fair values~~sale of the ~~assets~~ acquired well servicing rig business and ~~liabilities assumed,~~wireline business (collectively, “Pioneer Production Services”), to Clearwell Dynamics, LLC (“Clearwell”). The sale price was $43.0 million in cash consideration, subject to customary purchase price adjustments at closing for cash and ~~the~~working capital. The results of operations ~~for~~of these ~~acquired~~ businesses ~~will be included in our consolidated results~~were presented as a discontinued operation during the fourth quarter of ~~operations beginning in the quarter ending December 31,~~ 2021.

On December 30, 2021, we repaid the final $50 million of borrowings under the 2019 Term Loan Agreement (“Term Loan Agreement”), and as a result had no remaining borrowings under the Term Loan Agreement as of December 31, 2021.

Impact on our Business from Oil and Natural Gas Prices and Other Factors—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 when oil and natural gas prices are relatively low 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. 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. 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. ~~While the market for premium equipment has tightened, there remains 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 Item 1A of our Annual Report on Form 10-K for the fiscal year ended December 31, ~~2020.~~2021.

For the three ~~and nine~~ months ended ~~September~~June 30, ~~2021~~2022 and ~~2020,~~March 31, 2022 and six months ended June 30, 2022 and 2021, our operating revenues consisted of the following (dollars in thousands):


																	Three Months Ended								Six Months Ended
	Three Months Ended September 30,								Nine Months Ended September 30,								June 30,				March 31,				June 30,				June 30,
	2021				2020				2021				2020				2022				2022				2022				2021
Contract drilling	$	157,925	44.1	%	$	115,054	55.5	%	$	433,158	48.6	%	$	553,552	61.3	%	$	304,586	49.0	%	$	256,640	50.4	%	$	561,226	49.6	%	$	275,233	51.7	%
Pressure pumping		152,634	42.6	%		71,973	34.7	%		340,464	38.2	%		256,613	28.4	%		238,376	38.3	%		189,590	37.2	%		427,966	37.8	%		187,830	35.3	%
Directional drilling		31,728	8.9	%		10,271	5.0	%		76,267	8.6	%		56,498	6.3	%		54,825	8.8	%		43,334	8.5	%		98,159	8.7	%		44,539	8.4	%
Other operations		15,598	4.4	%		9,843	4.8	%		40,699	4.6	%		36,785	4.0	%		24,451	3.9	%		19,811	3.9	%		44,262	3.9	%		25,101	4.6	%
	$	357,885	100.0	%	$	207,141	100.0	%	$	890,588	100.0	%	$	903,448	100.0	%	$	622,238	100.0	%	$	509,375	100.0	%	$	1,131,613	100.0	%	$	532,703	100.0	%

Contract Drilling

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~~has in recent years referred to certain high specification rigs as “super-spec” ~~rigs. We~~rigs, which we consider ~~a super-spec rig~~ to be at least a 1,500 horsepower, ~~AC powered~~AC-powered rig that has at least a ~~750,000 pound~~750,000-pound hookload, a 7,500-psi circulating system, and is ~~pad capable.~~pad-capable. Due to evolving customer preferences, we have begun to refer to certain premium rigs as “Tier-1, super spec” rigs, which we consider as being a super-spec rig that also has a third mud pump and raised drawworks that allow for more clearance underneath the rig floor. As of ~~September~~June 30, ~~2021,~~2022, our rig fleet included ~~198 APEX~~®171 super-spec rigs, of which ~~150~~115 were ~~super-spec rigs. Subsequent to the completion of the Pioneer acquisition on October 1, 2021, our rig fleet included 215 APEX~~® ~~rigs, of which 166 are~~Tier-1, super-spec rigs.

Approximately ~~31%~~24% of the total contract drilling backlog in the United States at ~~September~~June 30, ~~2021~~2022 is reasonably expected to remain at ~~September~~June 30, ~~2022. We generally calculate our backlog by multiplying the dayrate under our term drilling contracts by the number~~2023. See Note 3 of ~~days remaining under the contract. The calculation does not include any revenues related~~Notes to ~~fees~~unaudited condensed consolidated financial statements 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, 2021. In addition, our term drilling contracts are generally subject to termination by the customeradditional information 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. Please see “Our Current Backlog of Contract Drilling Revenue May Decline and May Not Ultimately Be Realized, as Fixed-Term Contracts May in Certain Instances Be Terminated Without an Early Termination Payment” included in Item 1A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2020.backlog.

Pressure Pumping

As of ~~September~~June 30, ~~2021,~~2022, we had approximately ~~1.4~~1.1 million horsepower in our pressure pumping fleet. ~~The~~We provide pressure pumping ~~market has improved but remains oversupplied. In response~~services to ~~oversupplied market conditions, we implemented changes during~~oil and natural gas operators primarily in Texas and the ~~second quarter~~Appalachian region. Substantially all the revenue in the pressure pumping segment is from well stimulation services, such as hydraulic fracturing, for completion of ~~2020 that were intended to further streamline our operations, improve our efficiencies,~~new wells and ~~reduce our overall cost structure, while maintaining our customer service levels.~~remedial work on existing wells. We also provide cementing services through the pressure pumping segment.

Directional Drilling

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, measurement-while-drilling and supply and rental of downhole performance ~~motors and wireline steering tools.~~motors. We also provide services that improve the statistical accuracy of directional and horizontal ~~wellbore placement.~~wellbores.

Other Operations

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, andalong with 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.~~Mexico, provide the largest revenue contributions to our other operations. Other operations also includes the results of our electrical controls and automation business and the results of our drilling equipment service business.

~~For the three and nine months ended September 30, 2021 and 2020, our operating losses consisted of the following (in thousands):~~

Three Months Ended
September 30,

Nine Months Ended
September 30,

2021

2020

2021

2020

Contract drilling
$
(51,830
)

$
(47,214
)

$
(158,680
)

$
(481,974
)
Pressure pumping

(13,774
)

(30,856
)

(77,434
)

(134,896
)
Directional drilling

(4,581
)

(9,912
)

(14,614
)

(34,892
)
Other operations

(1,335
)

(6,421
)

(9,178
)

(35,547
)
Corporate

(18,489
)

(20,163
)

(57,040
)

(80,751
)

$
(90,009
)

$
(114,566
)

$
(316,946
)

$
(768,060
)

~~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 2021 was $83.0 million compared to a net loss of $112 million for the third quarter of 2020.~~

Results of Operations

The following tables summarize results of operations by business segment for the three months ended ~~September~~June 30, ~~2021~~2022 and ~~2020:~~March 31, 2022:

Contract Drilling

2021

2020

% Change

(dollars in thousands)

Revenues

$
157,925

$
115,054

37.3
%
Direct operating costs

111,537

59,117

88.7
%
Margin (1)

46,388

55,937

(17.1
)%
Other operating expenses (income), net

(28
)

—

NA

Selling, general and administrative

1,086

876

24.0
%
Depreciation, amortization and impairment

97,160

102,275

(5.0
)%
Operating loss

$
(51,830
)

$
(47,214
)

9.8
%
Operating days (2)

7,361

5,499

33.9
%
Average revenue per operating day

$
21.45

$
20.92

2.5
%
Average direct operating costs per operating day

$
15.15

$
10.75

40.9
%
Average margin per operating day (1)

$
6.30

$
10.17

(38.0
)%
Average rigs operating

80

60

33.9
%
Capital expenditures

$
21,239

$
9,502

123.5
%


	Three Months Ended
	June 30,			March 31,
Contract Drilling	2022			2022			% Change
	(dollars in thousands)
Revenues	$	304,586		$	256,640			18.7	%
Direct operating costs		196,269			176,706			11.1	%
Adjusted gross margin (1)		108,317			79,934			35.5	%
Selling, general and administrative		1,694			1,071			58.2	%
Depreciation, amortization and impairment		84,905			82,023			3.5	%
Other operating (income) expenses, net		(2	)		4		NA
Operating income (loss)	$	21,720		$	(3,164	)	NA
Operating days - U.S. (2)		11,015			10,362			6.3	%
Average revenue per operating day - U.S.	$	25.90		$	23.13			12.0	%
Average direct operating costs per operating day - U.S.	$	16.50		$	15.96			3.4	%
Average adjusted gross margin per operating day - U.S. (3)	$	9.39		$	7.17			30.9	%
Average rigs operating - U.S. (2)		121			115			5.1	%
Capital expenditures	$	50,165		$	51,710			(3.0	)%

(1)

~~Margin~~Adjusted gross margin is defined as revenues less direct operating costs ~~and excludes~~(excluding depreciation, amortization and impairment ~~other operating expenses (income), net and selling, general and administrative expenses. Average~~expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross margin ~~per operating day is defined as~~to adjusted gross margin ~~divided~~ by ~~operating days.~~segment.

(2)

A rig is considered to be operating if it is earning revenue pursuant to a contract on a given day. Average rigs operating is defined as operating days divided by the number of days in the period.

(3)

Average adjusted gross margin per operating day is defined as adjusted gross margin divided by operating days.

~~Total revenues~~Revenues increased primarily due to an increase in operating ~~days.~~days and improved pricing. Average revenue per operating day increased primarily due to improved pricing.

Direct operating costs increased due to ~~more~~an increase in operating days as well as inflationary pressure on labor and ~~higher operating costs. Direct~~supplies. Average direct operating costs per operating day increased primarily due to ~~a lower portion of our rigs being on standby, increased reactivation costs and inflationary~~ cost ~~pressure in the third quarter of 2021. Rigs on standby have very little associated cost.~~inflation.

Depreciation, amortization and impairment expense decreased due to lower cumulative capital expenditures in recent years, which reduced our depreciable asset base as depreciation, amortization and impairment outpaced capital expenditures between the periods.

~~The increase in capital expenditures was primarily due to upgrading of certain rig components and higher maintenance capital expenditures.~~

2826

Pressure Pumping

2021

2020

% Change

(dollars in thousands)

Revenues

$
152,634

$
71,973

112.1
%
Direct operating costs

134,726

63,721

111.4
%
Margin (1)

17,908

8,252

117.0
%
Selling, general and administrative

1,844

2,004

(8.0
)%
Depreciation, amortization and impairment

29,838

37,104

(19.6
)%
Operating loss

$
(13,774
)

$
(30,856
)

(55.4
)%
Average active spreads (2)

9

4

125.0
%
Effective utilization (3)

10.1

5.1

98.0
%
Fracturing jobs

116

69

68.1
%
Other jobs

185

180

2.8
%
Total jobs

301

249

20.9
%
Average revenue per fracturing job

$
1,265.98

$
960.70

31.8
%
Average revenue per other job

$
31.24

$
31.58

(1.1
)%
Average revenue per total job

$
507.09

$
289.05

75.4
%
Average direct operating costs per total job

$
447.59

$
255.91

74.9
%
Average margin per total job (1)

$
59.50

$
33.14

79.5
%
Margin as a percentage of revenues (1)

11.7
%

11.5
%

2.3
%
Capital expenditures

$
6,468

$
1,653

291.3
%


	Three Months Ended
	June 30,			March 31,
Pressure Pumping	2022			2022			% Change
	(dollars in thousands)
Revenues	$	238,376		$	189,590			25.7	%
Direct operating costs		191,455			157,468			21.6	%
Adjusted gross margin (1)		46,921			32,122			46.1	%
Selling, general and administrative		2,117			1,916			10.5	%
Depreciation, amortization and impairment		24,713			23,785			3.9	%
Operating income	$	20,091		$	6,421			212.9	%
Average active spreads (2)		11			11			(—	)%
Fracturing jobs		142			128			10.9	%
Other jobs		146			177			(17.5	)%
Total jobs		288			305			(5.6	)%
Average revenue per fracturing job	$	1,654.75		$	1,449.30			14.2	%
Average revenue per other job	$	23.30		$	23.05			1.1	%
Average revenue per total job	$	827.69		$	621.61			33.2	%
Average direct operating costs per total job	$	664.77		$	516.29			28.8	%
Average adjusted gross margin per total job (3)	$	162.92		$	105.32			54.7	%
Adjusted gross margin as a percentage of revenues (3)		19.7	%		16.9	%		16.2	%
Capital expenditures	$	34,554		$	33,462			3.3	%

(1)

~~Margin~~Adjusted gross margin is defined as revenues less direct operating costs ~~and excludes~~(excluding depreciation, amortization and impairment ~~and selling, general and administrative expenses. Average~~expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross margin ~~per total job is defined as~~to adjusted gross margin ~~divided~~ by ~~total jobs. Margin as a percentage of revenues is defined as margin divided by revenues.~~segment.

(2)

Average active spreads is the average number of spreads that were crewed and actively marketed during the period.

(3)

~~Effective utilization~~Average adjusted gross margin per total job is ~~calculated~~defined as ~~total pumping days during the quarter~~adjusted gross margin divided by ~~75 days, which we consider full effective utilization for~~total jobs. Adjusted gross margin as a ~~spread for the period.~~percentage of revenues is defined as adjusted gross margin divided by revenues.

Generally, the revenues in our pressure pumping segment are most impacted by ~~our~~the number and design 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 and the size of the jobs.

Our average revenue per total job increased due to improved pricing and a mix of activity weighted toward higher revenue fracturing jobs. Average direct operating costs per total job increased also as a result of the significant increase in fracturing jobs.

~~The increase in capital expenditures was primarily due to the increase in maintenance capital commensurate with higher activity in the third quarter of 2021.~~

Directional Drilling

2021

2020

% Change

(dollars in thousands)

Revenues

$
31,728

$
10,271

208.9
%
Direct operating costs

28,360

9,754

190.8
%
Margin (1)

3,368

517

551.5
%
Selling, general and administrative

1,177

829

42.0
%
Depreciation and amortization

6,772

9,600

(29.5
)%
Operating loss

$
(4,581
)

$
(9,912
)

(53.8
)%
Capital expenditures

$
3,290

$
510

545.1
%

~~(1)~~

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

~~Directional drilling revenue and direct operating costs~~Revenues increased primarily due to ~~increased job activity. We averaged 35 jobs per day~~an increase in the ~~third quarter~~number of ~~2021 as compared to 11~~higher revenue fracturing jobs, ~~per day~~improved pricing and continued improvement in ~~the third quarter of 2020.~~

~~Depreciation~~asset utilization and amortization expense decreased due to lower cumulative capital expenditures in recent years, which reduced our depreciable asset base as depreciation and amortization outpaced capital expenditures between the periods.

Other Operations

2021

2020

% Change

(dollars in thousands)

Revenues

$
15,598

$
9,843

58.5
%
Direct operating costs

10,444

8,665

20.5
%
Margin (1)

5,154

1,178

337.5
%
Selling, general and administrative

623

747

(16.6
)%
Depreciation, depletion, amortization and impairment

5,866

6,852

(14.4
)%
Operating loss

$
(1,335
)

$
(6,421
)

(79.2
)%
Capital expenditures

$
2,833

$
1,704

66.3
%

~~(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 and direct~~efficiency. Direct operating costs increased primarily due to an increase in the ~~volume~~number of ~~services provided~~higher cost fracturing jobs as well as inflationary pressure on labor and supplies.

Our average revenue per total job increased primarily as a result of a shift in the mix of total jobs toward higher revenue fracturing jobs. Average revenue per fracturing job increased primarily due to improved pricing. Average direct operating costs per total job increased partially as a result of a $9.9 million net benefit from a sales and use tax refund in the first quarter of 2022. Without this benefit, average direct operating costs per total job would have increased approximately 21% primarily as a result of a shift toward higher cost fracturing jobs as well as inflationary pressure on labor and supplies.


	Three Months Ended
	June 30,		March 31,
Directional Drilling	2022		2022		% Change
	(dollars in thousands)
Revenues	$	54,825	$	43,334		26.5	%
Direct operating costs		45,438		36,954		23.0	%
Adjusted gross margin (1)		9,387		6,380		47.1	%
Selling, general and administrative		1,500		1,248		20.2	%
Depreciation, amortization and impairment		3,859		3,344		15.4	%
Operating income	$	4,028	$	1,788		125.3	%
Capital expenditures	$	4,036	$	2,966		36.1	%

(1)

Adjusted gross margin is defined as revenues less direct operating costs (excluding depreciation, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross margin to adjusted gross margin by ~~our oilfield rentals business. Additionally,~~segment.

Directional drilling revenue increased primarily due to increased job activity and improved pricing. We averaged 46 jobs per day during the three months ended June 30, 2022 as compared to 42 jobs per day during the three months ended March 31, 2022.

Direct operating costs were higher by $8.5 million, or 23%, primarily due to increased job activity and cost inflation.


	Three Months Ended
	June 30,		March 31,
Other Operations	2022		2022		% Change
	(dollars in thousands)
Revenues	$	24,451	$	19,811		23.4	%
Direct operating costs		13,738		12,084		13.7	%
Adjusted gross margin (1)		10,713		7,727		38.6	%
Selling, general and administrative		610		589		3.6	%
Depreciation, depletion, amortization and impairment		6,803		6,397		6.3	%
Operating income	$	3,300	$	741		345.3	%
Capital expenditures	$	7,189	$	6,202		15.9	%

(1)

Adjusted gross margin is defined as revenues less direct operating costs (excluding depreciation, depletion, amortization and impairment expense). See Non-GAAP Financial Measures below for a ~~portion~~reconciliation of ~~the increase in other~~GAAP gross margin to adjusted gross margin by segment.

Other operations revenue ~~stemmed from~~increased primarily due to a ~~$2.5~~$2.7 million increase in ~~our~~ oil and natural gas revenues as a result of favorable crude oil market ~~prices. As a point of reference,~~prices and higher production. The average WTI-Cushing ~~prices~~price for the ~~third~~second quarter of ~~2021 were $70.58~~2022 was $108.72 per barrel as compared to ~~$40.89~~$94.45 per barrel in the ~~third~~first quarter of ~~2020. Since the increase in revenues was driven by market pricing, we did not have a commensurate increase in direct operating costs for our oil and natural gas business.~~2022.

Direct operating costs increased primarily due to increased activity levels and cost inflation.

~~Depreciation, depletion, amortization~~


	Three Months Ended
	June 30,			March 31,
Corporate	2022			2022			% Change
	(dollars in thousands)
Selling, general and administrative	$	20,158		$	22,637			(11.0	)%
Merger and integration expenses	$	182			1,863			(90.2	)%
Depreciation	$	1,273		$	1,389			(8.4	)%
Other operating (income) expenses, net
Net gain on asset disposals	$	(9,295	)	$	(1,113	)		735.1	%
Legal-related expenses and settlements		64			118			(45.8	)%
Research and development		247			245			0.8	%
Other		(252	)		(472	)		(46.6	)%
Other operating (income) expenses, net	$	(9,236	)	$	(1,222	)		655.8	%
Interest income	$	14		$	15			(6.7	)%
Interest expense	$	10,658		$	10,565			0.9	%
Other income (expense)	$	(2,452	)	$	1,582		NA
Capital expenditures	$	426		$	488			(12.7	)%

Selling, general and ~~impairment~~administrative expense decreased primarily due to ~~lower cumulative capital expenditures~~the fair value remeasurement of outstanding phantom unit awards in ~~recent years, which reduced our depreciable asset base~~the first quarter of 2022. We did not recognize a similar adjustment in the second quarter of 2022. See Note 11 of Notes to unaudited condensed consolidated financial statements for additional information on phantom unit awards as ~~depreciation, depletion, amortization and impairment outpaced capital expenditures between the periods.~~of June 30, 2022.

~~The increase in capital expenditures was primarily related to incremental spending in our oil and natural gas business.~~

Corporate

2021

2020

% Change

(dollars in thousands)

Selling, general and administrative

$
17,333

$
17,899

(3.2
)%
Merger and integration expenses

$
918

$
—

NA

Depreciation

$
1,429

$
1,488

(4.0
)%
Other operating expenses (income), net

Net gain on asset disposals

$
(1,543
)

$
(896
)

72.2
%
Legal-related expenses and settlements

103

830

(87.6
)%
Research and development

249

842

(70.4
)%
Other operating expenses (income), net

$
(1,191
)

$
776

NA

Interest income

$
37

$
238

(84.5
)%
Interest expense

$
10,683

$
11,288

(5.4
)%
Other income

$
14

$
512

(97.3
)%
Capital expenditures

$
434

$
73

494.5
%

Merger and integration expenses ~~were recognized in~~decreased as the ~~third quarter~~majority of ~~2021~~costs related to the Pioneer acquisition, which closed on October 1, ~~2021.~~2021, and the subsequent divestiture of Pioneer’s well servicing rig business and wireline business, which closed on December 31, 2021, were substantially complete in the first quarter of 2022.

Other operating (income) expenses, ~~(income),~~ net includes net gains associated with the disposal of assets. Accordingly, the related gains or losses have been excluded from the results of specific segments. The ~~majority of the~~$9.3 million net ~~gain on asset disposals during the third quarter of 2021 reflect gains on disposals of drilling equipment from our previously-closed Canadian operations. The~~ gain on asset disposals in the ~~third~~second quarter of ~~2020~~2022 was primarily due to the release of a $11.5 million cumulative translation adjustment from accumulated other comprehensive

income into net income (loss) in our condensed consolidated statements of operations upon substantially completing our exit from our Canadian operations.

The $4.0 million change in other income (expense) between the first quarter of 2022 and the second quarter of 2022 was primarily due to foreign currency adjustments related to ~~disposals of drilling equipment.~~our Colombian operations.

The following tables summarize results of operations by business segment for the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022, and ~~2020:~~June 30, 2021:

Contract Drilling

2021

2020

% Change

(dollars in thousands)

Revenues

$
433,158

$
553,552

(21.7
)%
Direct operating costs

291,049

309,664

(6.0
)%
Margin (1)

142,109

243,888

(41.7
)%
Restructuring expenses

—

2,430

(100.0
)%
Other operating expenses (income), net

17

(4,155
)

NA

Selling, general and administrative

3,346

3,684

(9.2
)%
Depreciation, amortization and impairment

297,426

328,843

(9.6
)%
Impairment of goodwill

—

395,060

(100.0
)%
Operating loss

$
(158,680
)

$
(481,974
)

(67.1
)%
Operating days (2)

20,196

24,184

(16.5
)%
Average revenue per operating day

$
21.45

$
22.89

(6.3
)%
Average direct operating costs per operating day

$
14.41

$
12.80

12.6
%
Average margin per operating day (1)

$
7.04

$
10.08

(30.2
)%
Average rigs operating

74

88

(15.9
)%
Capital expenditures

$
56,708

$
101,448

(44.1
)%


	Six Months Ended
	June 30,		June 30,
Contract Drilling	2022		2021			% Change
	(dollars in thousands)
Revenues	$	561,226	$	275,233			103.9	%
Direct operating costs		372,975		179,512			107.8	%
Adjusted gross margin (1)		188,251		95,721			96.7	%
Other operating expenses, net		2		45			(95.6	)%
Selling, general and administrative		2,765		2,260			22.3	%
Depreciation, amortization and impairment		166,928		200,266			(16.6	)%
Operating income (loss)	$	18,556	$	(106,850	)	NA
Operating days - U.S. (2)		21,377		12,835			66.6	%
Average revenue per operating day - U.S.	$	24.56	$	21.44			14.5	%
Average direct operating costs per operating day - U.S.	$	16.24	$	13.98			16.2	%
Average adjusted gross margin per operating day - U.S. (3)	$	8.32	$	7.47			11.4	%
Average rigs operating - U.S. (2)		118		71			66.6	%
Capital expenditures	$	101,875	$	35,469			187.2	%

(1)

~~Margin~~Adjusted gross margin is defined as revenues less direct operating costs ~~and excludes restructuring expenses,~~(excluding depreciation, amortization and impairment ~~impairment~~expense). See Non-GAAP Financial Measures below for a reconciliation of ~~goodwill, other operating expenses (income), net and selling, general and administrative expenses. Average~~GAAP gross margin ~~per operating day is defined as~~to adjusted gross margin ~~divided~~ by ~~operating days.~~segment.

(2)

A rig is considered to be operating if it is earning revenue pursuant to a contract on a given day. Average rigs operating is defined as operating days divided by the number of days in the period.

(3)

Average adjusted gross margin per operating day is defined as adjusted gross margin divided by operating days.

~~Generally, the revenues~~Revenues increased primarily due to an increase in ~~our contract drilling segment are most impacted by two primary factors: our average number of rigs~~ operating days and ~~our average revenue per operating day. Our average~~improved pricing. Average revenue per operating day is largely dependent on the pricing terms of our rig contracts. Lump sum early termination revenues were $3.3 million during the nine months ended September 30, 2021, which was less than the $13.3 million recorded during the comparable period of 2020.

~~Revenues and direct operating costs decreased~~increased primarily due to ~~a decrease~~improved pricing.

Direct operating costs increased due to an increase in operating ~~days. Additionally, revenues decreased due to the reduction of lump sum early termination revenues recorded during the nine months ended September 30, 2020 that did not recur in 2021.~~days, increased reactivation costs and inflationary pressure on labor and supplies. Average direct operating costs per operating day increased primarily due to a ~~reduction~~lower portion of our rigs being on standby, increased reactivation costs and inflationary cost pressure beginning in the ~~proportion~~second half of ~~rigs on standby and rig reactivation costs.~~2021. Rigs on standby have very little associated cost.

~~Restructuring expenses were recognized in 2020 and primarily related to severance costs.~~

~~The change in other operating expenses (income), net is primarily due to an insurance reimbursement for damaged drilling equipment in 2020.~~

Depreciation, amortization and impairment expense decreased primarily due to a lower ~~cumulative capital expenditures in recent years, which reduced our~~ depreciable asset base during the six months ended June 30, 2022 as ~~depreciation, amortization~~a result of a $220 million impairment charge taken in the fourth quarter of 2021. The impairment charge was related to the abandonment of 43 legacy non-super-spec rigs and ~~impairment outpaced capital expenditures between the periods.~~equipment.

All of the goodwill associated with our contract drilling reporting unit was impaired during the nine months ended September 30, 2020. See Note 7 of Notes to unaudited condensed consolidated financial statements for additional information.

The ~~decrease~~increase in capital expenditures was primarily due to ~~reduced~~higher maintenance capital expenditures ~~in 2021 due to lower activity~~ and ~~the delivery~~upgrading of ~~equipment in 2020 which was ordered prior to the industry downturn.~~certain rig components.

3129

Pressure Pumping

2021

2020

% Change

(dollars in thousands)

Revenues

$
340,464

$
256,613

32.7
%
Direct operating costs

313,556

234,844

33.5
%
Margin (1)

26,908

21,769

23.6
%
Restructuring expenses

—

31,331

(100.0
)%
Selling, general and administrative

5,379

6,748

(20.3
)%
Depreciation, amortization and impairment

98,963

118,586

(16.5
)%
Operating income (loss)

$
(77,434
)

$
(134,896
)

(42.6
)%
Average active spreads (2)

7

6

16.7
%
Effective utilization (3)

7.9

5.4

46.3
%
Fracturing jobs

292

193

51.3
%
Other jobs

591

541

9.2
%
Total jobs

883

734

20.3
%
Average revenue per fracturing job

$
1,102.58

$
1,251.37

(11.9
)%
Average revenue per other job

$
31.32

$
27.91

12.2
%
Average revenue per total job

$
385.58

$
349.61

10.3
%
Average direct operating costs per total job

$
355.10

$
319.95

11.0
%
Average margin per total job (1)

$
30.47

$
29.66

2.7
%
Margin as a percentage of revenues (1)

7.9
%

8.5
%

(7.1
)%
Capital expenditures and acquisitions

$
19,457

$
17,880

8.8
%


	Six Months Ended
	June 30,			June 30,
Pressure Pumping	2022			2021			% Change
	(dollars in thousands)
Revenues	$	427,966		$	187,830			127.8	%
Direct operating costs		348,923			178,830			95.1	%
Adjusted gross margin (1)		79,043			9,000			778.3	%
Selling, general and administrative		4,033			3,535			14.1	%
Depreciation, amortization and impairment		48,498			69,125			(29.8	)%
Operating income (loss)	$	26,512		$	(63,660	)	NA
Average active spreads (2)		11			7			57.1	%
Fracturing jobs		270			176			53.4	%
Other jobs		323			406			(20.4	)%
Total jobs		593			582			1.9	%
Average revenue per fracturing job	$	1,557.35		$	994.88			56.5	%
Average revenue per other job	$	23.16		$	31.36			(26.1	)%
Average revenue per total job	$	721.70		$	322.73			123.6	%
Average direct operating costs per total job	$	588.40		$	307.27			91.5	%
Average adjusted gross margin per total job (3)	$	133.29		$	15.46			762.2	%
Adjusted gross margin as a percentage of revenues (3)		18.5	%		4.8	%		284.8	%
Capital expenditures	$	68,016		$	12,989			423.6	%

(1)

~~Margin~~Adjusted gross margin is defined as revenues less direct operating costs ~~and excludes restructuring expenses,~~(excluding depreciation, amortization and impairment ~~and selling, general and administrative expenses. Average~~expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross margin ~~per total job is defined as~~to adjusted gross margin ~~divided~~ by ~~total jobs. Margin as a percentage of revenues is defined as margin divided by revenues.~~segment.

(2)

Average active spreads is the average number of spreads that were crewed and actively marketed during the period.

(3)

~~Effective utilization~~Average adjusted gross margin per total job is ~~calculated~~defined as ~~total pumping days during the first nine months of the year~~adjusted gross margin divided by ~~225 days, which we consider full effective utilization for~~total jobs. Adjusted gross margin as a ~~spread for the period.~~percentage of revenues is defined as adjusted gross margin divided by revenues.

Revenues increased primarily due to an increase in the number of higher revenue fracturing jobs, improved pricing and ~~direct~~continued improvement in asset utilization and efficiency. Direct operating costs increased primarily due to an increase in the number of higher cost fracturing jobs as ~~activity levels continue to recover from the industry downturn in 2020. Average~~well as inflationary pressure on labor and supplies.

Our average revenue per total job increased primarily ~~due to~~as a result of a shift in the mix of ~~activity weighted~~total jobs toward higher revenue fracturing jobs. Average revenue per fracturing job increased primarily due to improved pricing. Average direct operating costs per total job increased ~~also as a result of the significant increase in fracturing jobs, which generally have higher direct operating costs.~~

Restructuring expenses were recognized during the nine months ended September 30, 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.

~~Selling, general and administrative expenses decreased~~ primarily as a result of a shift toward higher cost ~~reduction efforts.~~fracturing jobs as well as inflationary pressure on labor and supplies.

Depreciation, amortization and impairment expense decreased primarily due to a lower ~~cumulative capital expenditures in recent years, which reduced our~~ depreciable asset base during the six months ended June 30, 2022 as ~~depreciation, amortization and~~a result of a $32.2 million impairment ~~outpaced~~charge taken in the fourth quarter of 2021. This impairment charge was related to the abandonment of approximately 0.2 million horsepower within our pressure pumping fleet.

The increase in capital expenditures ~~between~~was primarily due to costs associated with reactivating stacked equipment as well as upgrades and the ~~periods.~~increase in maintenance capital expenditures associated with a higher average number of active spreads.


	Six Months Ended
	June 30,		June 30,
Directional Drilling	2022		2021			% Change
	(dollars in thousands)
Revenues	$	98,159	$	44,539			120.4	%
Direct operating costs		82,392		39,007			111.2	%
Adjusted gross margin (1)		15,767		5,532			185.0	%
Selling, general and administrative		2,748		2,474			11.1	%
Depreciation, amortization and impairment		7,203		13,091			(45.0	)%
Operating income (loss)	$	5,816	$	(10,033	)	NA
Capital expenditures	$	7,002	$	1,323			429.3	%

3230

Directional Drilling

2021

2020

% Change

(dollars in thousands)

Revenues

$
76,267

$
56,498

35.0
%
Direct operating costs

67,367

54,348

24.0
%
Margin (1)

8,900

2,150

314.0
%
Restructuring expenses

—

3,175

(100.0
)%
Selling, general and administrative

3,651

4,169

(12.4
)%
Depreciation, amortization and impairment

19,863

29,698

(33.1
)%
Operating loss

$
(14,614
)

$
(34,892
)

(58.1
)%
Capital expenditures

$
4,613

$
4,562

1.1
%

(1)

~~Margin~~Adjusted gross margin is defined as revenues less direct operating costs ~~and excludes restructuring expenses,~~(excluding depreciation, amortization and impairment ~~and selling, general and administrative expenses.~~expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross margin to adjusted gross margin by segment.

Directional drilling revenue ~~and direct operating costs~~ increased ~~from the nine months ended September 30, 2020~~ primarily due to increased job ~~activity.~~activity and improved pricing. We averaged 2844 jobs per day during the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 as compared to 1925 jobs per day ~~for~~during the ~~comparable period in 2020.~~six months ended June 30, 2021.

~~Restructuring expenses~~

Direct operating costs were ~~recognized in 2020~~higher by $43.4 million, or 111%, primarily due to increased job activity and ~~were primarily attributable to severance and ROU asset abandonments.~~cost inflation.

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

Depreciation, amortization and impairment expense decreased primarily due to a lower ~~cumulative capital expenditures in recent years, which reduced our~~ depreciable asset base during the six months ended June 30, 2022 as ~~depreciation, amortization~~a result of the abandonment of an $11.4 million developed technology intangible asset and ~~impairment outpaced capital expenditures between~~$2.5 million of directional drilling equipment during the ~~periods.~~fourth quarter of 2021.

Capital expenditures increased due to higher levels of activity requiring premium equipment to meet market demands.

Other Operations

2021

2020

% Change

(dollars in thousands)

Revenues

$
40,699

$
36,785

10.6
%
Direct operating costs

31,079

33,775

(8.0
)%
Margin (1)

9,620

3,010

219.6
%
Restructuring expenses

—

501

(100.0
)%
Selling, general and administrative

1,489

2,969

(49.8
)%
Depreciation, depletion, amortization and impairment

17,309

35,087

(50.7
)%
Operating loss

$
(9,178
)

$
(35,547
)

(74.2
)%
Capital expenditures

$
9,006

$
9,776

(7.9
)%


	Six Months Ended
	June 30,		June 30,
Other Operations	2022		2021			% Change
	(dollars in thousands)
Revenues	$	44,262	$	25,101			76.3	%
Direct operating costs		25,822		20,635			25.1	%
Adjusted gross margin (1)		18,440		4,466			312.9	%
Selling, general and administrative		1,199		866			38.5	%
Depreciation, depletion, amortization and impairment		13,200		11,443			15.4	%
Operating income (loss)	$	4,041	$	(7,843	)	NA
Capital expenditures	$	13,391	$	6,173			116.9	%

(1)

~~Margin~~Adjusted gross margin is defined as revenues less direct operating costs ~~and excludes restructuring expenses,~~(excluding depreciation, depletion, amortization and impairment ~~and selling, general and administrative expenses.~~expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross margin to adjusted gross margin by segment.

Other operations revenue and direct operating costs increased ~~from the nine~~ ~~months ended September 30,~~ ~~2020~~ primarily due to a ~~$5.1~~$9.6 million increase in ~~our~~ oil and natural gas revenues as a result of favorable crude oil market ~~prices.~~prices and higher production as well as a $7.9 million increase in our oilfield rentals business revenues due to a higher volume of services. Average WTI-Cushing prices for the ~~first nine~~six months ~~of 2021~~ended June 30, 2022 were ~~$65.05~~$102.01 per barrel as compared to ~~$38.17~~$62.21 per barrel in the ~~first nine~~six months ~~of 2020. We recognized a $1.2 million decrease in revenue from our drilling equipment service business as a result of reduced activity in 2021, which partially offset the~~ended June 30, 2021. The increase in ~~revenue~~direct operating costs was primarily related to incremental production costs from our oil and natural gas ~~business.~~

~~Other operations direct operating costs decreased from the nine~~ ~~months ended September 30,~~ ~~2020 primarily due to~~assets as well as a ~~$2.3 million decrease from~~higher volume of services provided by our oilfield rentals ~~business. The reduction was due to~~business and cost ~~reduction efforts implemented in 2020.~~inflation.

The increase in capital expenditures was primarily related to incremental spending in our oilfield rentals and oil and natural gas businesses.

~~Restructuring expenses were recognized during the nine months ended~~ ~~September~~ ~~30, 2020 and related to severance costs.~~


	Six Months Ended
	June 30,			June 30,
Corporate	2022			2021			% Change
	(dollars in thousands)
Selling, general and administrative	$	42,795		$	36,978			15.7	%
Merger and integration expenses	$	2,045		$	1,148			78.1	%
Depreciation	$	2,662		$	2,994			(11.1	)%
Other operating (income) expenses, net
Net gain on asset disposals	$	(10,408	)	$	(4,052	)		156.9	%
Legal-related expenses and settlements		182			611			(70.2	)%
Research and development		492			872			(43.6	)%
Other		(724	)		—		NA
Other operating (income) expenses, net	$	(10,458	)	$	(2,569	)		307.1	%
Interest income	$	29		$	159			(81.8	)%
Interest expense	$	21,223		$	20,713			2.5	%
Other income (expense)	$	(870	)	$	826		NA
Capital expenditures	$	914		$	619			47.7	%

Selling, general and administrative expense ~~decreased~~increased primarily due to increased personnel costs as a result of ~~cost reduction efforts.~~

~~Depreciation, depletion, amortization~~higher headcount, wage growth and impairment decreased primarily due to the $11.2 million impairment we recognized during the nine months ended September 30, 2020 related to certain of our oil and natural gas assets. The impairment reduced our depreciable base, which lowered depreciationchanges in ~~subsequent periods. Additionally, the decrease in depreciation, depletion, amortization~~stock-based compensation.

and impairment was partially due to lower cumulative capital expenditures in recent years, which reduced our depreciable asset base as depreciation, depletion, amortization and impairment outpaced capital expenditures between the periods.

Corporate

2021

2020

% Change

(dollars in thousands)

Selling, general and administrative

$
54,311

$
59,122

(8.1
)%
Restructuring expenses

$
—

$
901

(100.0
)%
Merger and integration expenses

$
2,066

$
—

NA

Depreciation

$
4,423

$
4,987

(11.3
)%
Other operating expenses (income), net

Net gain on asset disposals

$
(5,595
)

$
(3,357
)

66.7
%
Legal-related expenses and settlements

714

1,680

(57.5
)%
Research and development

1,121

2,580

(56.6
)%
Other

—

9,232

(100.0
)%
Other operating expenses (income), net

$
(3,760
)

$
10,135

NA

Credit loss expense

$
—

$
5,606

(100.0
)%
Interest income

$
196

$
1,229

(84.1
)%
Interest expense

$
31,396

$
33,496

(6.3
)%
Other income

$
840

$
682

23.2
%
Capital expenditures

$
1,053

$
1,377

(23.5
)%

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

~~Restructuring expenses were recognized during the nine months ended September 30, 2020 and were primarily attributable to severance and ROU asset abandonments.~~

~~Merger and integration expenses were recognized during the nine months ended September 30, 2021 related to the Pioneer acquisition, which closed on October 1, 2021.~~

Other operating (income) expenses, ~~(income),~~ net includes net gains associated with the disposal of assets. Accordingly, the related gains or losses have been excluded from the results of specific segments. The $10.4 million gain on asset disposals during the six months ended June 30, 2022 was primarily due to the release of a $11.5 million cumulative translation adjustment from accumulated other comprehensive income into net income (loss) in our condensed consolidated statements of operations upon substantially completing our exit from our Canadian operations. The majority of the net gain on asset disposals during the ~~nine~~six months ended ~~September~~June 30, 2021 reflect gains on disposals of buildings ~~land~~ and ~~drilling equipment, while the gain on asset disposals~~land.

The $1.7 million change in ~~2020~~other income (expense) was primarily due to foreign currency adjustments related to disposals of drilling and pressure pumping equipment. Additionally, other operating expenses (income), net includes charges of $9.2 million in the second quarter of 2020 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 during the nine months ended September 30, 2020.Colombian operations.

~~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.~~

Lower interest expense for the nine months ended September 30, 2021 includes the effect of the early repayment of long-term debt in the fourth quarter of 2020. We elected to repay a portion of the borrowings outstanding under our Term Loan Agreement and repurchase portions of our 2028 Senior Notes and our 2029 Senior Notes, which reduced our aggregate principal amounts outstanding by $66.2 million.

Income Taxes

Our effective income tax rate for the three months ended ~~September~~June 30, ~~2021~~2022 was ~~17.5%~~7.5%, compared with ~~10.4%~~(3.3)% for the three months ended ~~September 30, 2020.~~March 31, 2022. The higher effective income tax rate for the three months ended ~~September~~June 30, ~~2021~~2022 was primarily attributable to pre-tax income recognized in the ~~non-deductible portion~~second quarter of 2022 versus pre-tax loss recognized in the ~~goodwill impairment~~first quarter of 2022, as well as incremental income tax expense included in the ~~2020 estimated annual effective tax rate. This was partially offset by the valuation allowance included in the 2021 estimated annual effective tax rate.~~second quarter of 2022 for Colombia and certain U.S. states.‌

Our effective income tax rate for the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 was ~~15.7%~~(64.7)%, compared with ~~12.8%~~15.0% for the ~~nine~~six months ended ~~September~~June 30, ~~2020.~~2021. The ~~higher~~lower effective income tax rate for the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 was primarily attributable to the ~~non-deductible portion~~impact of valuation allowances between periods. For the ~~goodwill impairment included~~period ending June 30, 2022, due to valuation allowances, only certain income tax expense related to Colombia and certain U.S. states was recorded, during a period with a pre-tax loss. This resulted in ~~the 2020 estimated annual~~a negative effective ~~tax rate. This was partially offset by the valuation allowance included in the 2021 estimated annual effective~~income tax rate ~~and also state rate changes enacted during 2021.~~for the six months ended June 30, 2022.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized, and when necessary valuation allowances are provided. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. We assess the realizability of our deferred tax assets quarterly and consider carryback availability, the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. In the third quarter of 2021, the effective tax rate takes into consideration the estimated valuation allowance based on forecasted 2021 income.

Liquidity and Capital Resources

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 second quarter of 2020. We completed the restructuring plan during the third quarter of 2020 and did not incur additional expenses related to the plan. There have been no restructuring charges in 2021.

~~While oilfield services activity and revenues declined significantly throughout 2020, we aligned our cost structure with the changing activity levels and enhanced our liquidity position.~~

Our primary sources of liquidity are cash and cash equivalents, availability under our revolving credit facility and cash provided by operating activities. As of ~~September~~June 30, ~~2021,~~2022, we had approximately ~~$205~~$173 million in working capital, including ~~$191~~$19.6 million of cash and cash equivalents, and approximately ~~$600~~$575 million available under our revolving credit facility.

We have an amended and restated credit agreement (the “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. As of ~~September~~June 30, ~~2021,~~2022, we had ~~no borrowings~~$25.0 million outstanding under our revolving credit facility ~~and~~at a base rate of 5.5%. We had $0.1 million in letters of credit outstanding under the Credit Agreement at June 30, 2022 and, as a result, had available borrowing capacity of approximately ~~$600~~$575 million at that date. Of the revolving credit commitments, $50 million expires on March 27, 2024, and the remaining $550 million expires on March 27, 2025. 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. Additionally, we have the option, subject to certain conditions, to exercise one 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, as described in “Item 3” below. If our credit rating is below investment grade at both Moody’s and S&P, we will become subject to a restricted payment covenant. The Credit Agreement also contains a financial covenant that requires our total debt to capitalization ratio, expressed as a percentage, not exceed 50%.

We also have a senior unsecured term loan agreement (“Term Loan Agreement”) that matures on June 10, 2022. The Term Loan Agreement permitted a single borrowing of up to $150 million, which we drew in full in 2019. Subject to customary conditions, we may request that lenders’ aggregate commitments be increased by up to $75 million, not to exceed total commitments of $225 million. During 2019 and 2020, we repaid a total of $100 million of borrowings under the Term Loan Agreement. The Term Loan Agreement contains the same covenants as the Credit Agreement, as well as a covenant requiring mandatory prepayment upon the issuance of new senior indebtedness in certain circumstances if our credit rating is below investment grade at both Moody’s and S&P. As of September 30, 2021, we had $50 million of borrowings remaining outstanding under the Term Loan Agreement at a LIBOR-based interest rate of 1.46%.

We also have 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. 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. 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.

Our outstanding debt at ~~September~~June 30, ~~2021~~2022 was ~~$909~~$884 million and consisted of $510 million of 3.95% Senior Notes due 2028 (the “2028 Notes”), $349 million of 5.15% Senior Notes due 2029 (the “2029 Notes”) and ~~$50~~$25.0 million ~~of borrowings~~ under ~~the Term Loan Agreement.~~our revolving credit facility. We were in compliance with all covenants at ~~September~~June 30, ~~2021.~~2022.

For a full description of the Credit ~~Agreement, the Term Loan~~ Agreement, the Reimbursement Agreement, the 2028 Notes and the 2029 Notes, please see Note 98 of Notes to unaudited condensed consolidated financial statements.

We had ~~$63.7~~$65.1 million of outstanding letters of credit at ~~September~~June 30, ~~2021,~~2022, which were comprised of ~~$63.6~~$65.0 million outstanding under the Reimbursement Agreement and $0.1 million outstanding under the Credit Agreement. We maintain these letters of credit primarily for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under 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~~June 30, ~~2021,~~2022, no amounts had been drawn under the letters of credit.

Operating lease liabilities totaled $21.7 million at September 30, 2021. There have been no material changes to our contractual obligations table that was included in our 2020 Annual Report. See Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the fiscal year ended December 31, 2020.

Cash Requirements

~~See Note 10 of Notes to unaudited condensed consolidated financial statements for additional information on our current commitments and contingencies as of September 30, 2021.~~

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.

A portion of our capital expenditures can be adjusted and managed by us to match market demand and activity levels. Based on our current outlook for activity, we have increased our 2022 capital expenditures forecast to approximately $390 million.

The majority of these expenditures are expected to be used for normal, recurring items necessary to support our business.

During the ~~nine~~six months ended ~~September~~June 30, ~~2021,~~2022, our sources of cash flow included:

•

$~~51.6~~85.0 million from operating activities, ~~and~~

•

$~~20.6~~15.3 million in proceeds from the disposal of property and ~~equipment.~~equipment, and

•

$25.0 million in net borrowings under our revolving credit facility.

During the ~~nine~~six months ended ~~September~~June 30, ~~2021,~~2022, we used ~~$11.3~~$17.3 million to pay dividends on our common stock ~~$3.6 million to purchase treasury stock~~ and ~~$90.8~~$194 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 contract 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.

~~Based on conversations with customers about increasing activity levels into 2022, we increased our 2021 capital expenditure forecast to approximately $170 million.~~

We paid cash dividends during the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 as follows:


	Per Share		Total
			(in thousands)
Paid on March 17, 2022	$	0.04	$	8,611
Paid on June 16, 2022		0.04		8,652
	$	0.08	$	17,263

Per Share

Total

(in thousands)

Paid on March 18, 2021
$
0.02

$
3,754

Paid on June 17, 2021

0.02

3,769

Paid on September 16, 2021

0.02

3,780

$
0.06

$
11,303

On ~~October~~July 27, ~~2021,~~2022, our Board of Directors approved a cash dividend on our common stock in the amount of ~~$0.02~~$0.04 per share to be paid on ~~December 16, 2021~~September 15, 2022 to holders of record as of ~~December 2, 2021.~~September 1, 2022. 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. Our Board of Directors may, without advance notice, reduce or suspend our dividend in order to improve our financial flexibility and position our company for long-term success. There can be no assurance that we will pay a dividend in the future.

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.

OnIn 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. The authorized repurchases under this program were subsequently increased inprogram. In July ~~2018 and February 2019, and on July 24,~~ 2019, our Board of Directors ~~approved another increase of~~increased the ~~authorization~~amount authorized to be repurchased under the ~~stock buyback~~ program to ~~allow for~~up to $250 million of ~~future share repurchases.~~our common stock. 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~~June 30, ~~2021,~~2022, 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.

Treasury stock acquisitions during the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 were as follows (dollars in thousands):


	Shares		Cost		Shares		Cost
Treasury shares at beginning of period		83,402,322	$	1,366,313		84,128,995	$	1,372,641
Acquisitions pursuant to long-term incentive plan (1)		434,224		3,574		1,372,101		23,237
Other						3,027		28
Treasury shares at end of period		83,836,546	$	1,369,887		85,504,123	$	1,395,906

(1)

We withheld ~~434,224~~1,372,101 shares during the first ~~three~~two quarters of ~~2021~~2022 with respect to exercise price and employees’ tax withholding obligations upon the exercise of stock options and employees’ tax withholding obligations upon the settlement of performance unit awards and 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 (the “2014 Plan”) and the Patterson-UTI Energy, Inc. 2021 Long-Term Incentive Plan (the “2021 Plan”), and not pursuant to the stock buyback program.

As of ~~September~~June 30, ~~2021,~~2022, we had unrecognized compensation costs of ~~$20.9~~$34.2 million and ~~$8.1~~$14.3 million related to our unvested restricted stock units and our unvested Performance Units, respectively. The weighted-average remaining vesting periods for these awards were ~~1.84~~1.90 years and 1.70 years, respectively as of ~~September~~June 30, ~~2021.~~2022. See Note 1211 of Notes to unaudited condensed consolidated financial statements for additional discussion regarding our stock-based compensation.

Commitments — As of June 30, 2022, we had commitments to purchase major equipment totaling approximately $97.8 million for our drilling, pressure pumping, directional drilling and oilfield rentals businesses. Our pressure pumping business has entered into agreements to purchase minimum quantities of proppants and chemicals from certain vendors. As of June 30, 2022, the remaining minimum obligation under these agreements was approximately $16.1 million.

See Note 9 of Notes to unaudited condensed consolidated financial statements for additional information on our current commitments and contingencies as of June 30, 2022.

Operating lease liabilities totaled $27.3 million at June 30, 2022. There have been no material changes to our operating lease liabilities since December 31, 2021.

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.

Non-GAAP Financial Measures

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).~~expense. 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~~non-GAAP financial measure of Adjusted EBITDA to the ~~U.S.~~ GAAP financial measure of net income (loss).


	Three Months Ended					Six Months Ended
	June 30,		March 31,			June 30,
	2022		2022			2022			2021
	(in thousands)
Net income (loss)	$	21,886	$	(28,777	)	$	(6,891	)	$	(209,722	)
Income tax expense (benefit)		1,780		928			2,708			(36,943	)
Net interest expense		10,644		10,550			21,194			20,554
Depreciation, depletion, amortization and impairment		121,553		116,938			238,491			296,919
Adjusted EBITDA	$	155,863	$	99,639		$	255,502		$	70,808

Three Months Ended

Nine Months Ended

September 30,

September 30,

2021

2020

2021

2020

(in thousands)

Net loss
$
(82,998
)

$
(112,111
)

$
(292,720
)

$
(697,165
)
Income tax benefit

(17,643
)

(12,993
)

(54,586
)

(102,480
)
Net interest expense

10,646

11,050

31,200

32,267

Depreciation, depletion, amortization and impairment

141,065

157,319

437,984

517,201

Impairment of goodwill

—

—

—

395,060

Adjusted EBITDA
$
51,070

$
43,265

$
121,878

$
144,883

Adjusted Gross Margin

We define “Adjusted gross margin” as revenues less direct operating costs (excluding depreciation, depletion, amortization and impairment expense). Adjusted gross margin is included as a supplemental disclosure because it is a useful indicator of our operating performance.


	Contract Drilling			Pressure Pumping			Directional Drilling			Other Operations
	(in thousands)
For the three months ended June 30, 2022
Revenues	$	304,586		$	238,376		$	54,825		$	24,451
Less direct operating costs		(196,269	)		(191,455	)		(45,438	)		(13,738	)
Less depreciation, depletion, amortization and impairment		(84,905	)		(24,713	)		(3,859	)		(6,803	)
GAAP gross margin		23,412			22,208			5,528			3,910
Depreciation, depletion, amortization and impairment		84,905			24,713			3,859			6,803
Adjusted gross margin	$	108,317		$	46,921		$	9,387		$	10,713

For the three months ended March 31, 2022
Revenues	$	256,640		$	189,590		$	43,334		$	19,811
Less direct operating costs		(176,706	)		(157,468	)		(36,954	)		(12,084	)
Less depreciation, depletion, amortization and impairment		(82,023	)		(23,785	)		(3,344	)		(6,397	)
GAAP gross margin		(2,089	)		8,337			3,036			1,330
Depreciation, depletion, amortization and impairment		82,023			23,785			3,344			6,397
Adjusted gross margin	$	79,934		$	32,122		$	6,380		$	7,727

For the six months ended June 30, 2022
Revenues	$	561,226		$	427,966		$	98,159		$	44,262
Less direct operating costs		(372,975	)		(348,923	)		(82,392	)		(25,822	)
Less depreciation, depletion, amortization and impairment		(166,928	)		(48,498	)		(7,203	)		(13,200	)
GAAP gross margin		21,323			30,545			8,564			5,240
Depreciation, depletion, amortization and impairment		166,928			48,498			7,203			13,200
Adjusted gross margin	$	188,251		$	79,043		$	15,767		$	18,440

For the six months ended June 30, 2021
Revenues	$	275,233		$	187,830		$	44,539		$	25,101
Less direct operating costs		(179,512	)		(178,830	)		(39,007	)		(20,635	)
Less depreciation, depletion, amortization and impairment		(200,266	)		(69,125	)		(13,091	)		(11,443	)
GAAP gross margin		(104,545	)		(60,125	)		(7,559	)		(6,977	)
Depreciation, depletion, amortization and impairment		200,266			69,125			13,091			11,443
Adjusted gross margin	$	95,721		$	9,000		$	5,532		$	4,466

Critical Accounting Estimates

Our consolidated financial statements are impacted by certain estimates and assumptions made by management. A detailed discussion of our critical accounting estimates is included in our Annual Report on Form 10-K for the fiscal year ended December 31, ~~2020.~~2021. There have been no material changes in these critical accounting estimates.

~~Key estimates used by management include:~~



~~allowance for credit losses — see Note 4 of Notes to consolidated financial statements within our Annual Report on Form 10-K for the fiscal year ended December 31, 2020,~~



~~depreciation, depletion and amortization — see Notes 1 and 6 of Notes to consolidated financial statements within our Annual Report on Form 10-K for the fiscal year ended December 31, 2020,~~



~~goodwill and long-lived asset impairments — see Notes 6 and 7 of Notes to consolidated financial statements within our Annual Report on Form 10-K for the fiscal year ended December 31, 2020, and~~



self-insured levels of insurance coverage — see Note 10 of Notes to consolidated financial statements within our Annual Report on Form 10-K for the fiscal year ended December 31, 2020. We maintain insurance coverage for fire, windstorm and other risks of physical loss to our equipment and certain other assets, employers’ liability, automobile liability, commercial general liability, workers’ compensation and insurance for other specific risks. We also self-insure a number of other risks, including loss of earnings and business interruption and most cybersecurity risks, and do not carry a significant amount of insurance to cover risks of underground reservoir damage. Our insurance accruals are based on claims filed and estimates of claims incurred but not reported and are developed by our management with assistance from our third-party actuary and third-party claims administrator. The insurance accruals are influenced by our past claims experience factors, which have a limited history, and by published industry development factors. If we experience insurance claims or costs above or below our historically evaluated levels, our estimates could be materially affected. The frequency and number of claims or incidents could vary significantly over time, which could materially affect our self-insurance liabilities. Additionally, the actual costs to settle the self-insurance liabilities could materially differ from the original estimates and cause us to incur additional costs in future periods associated with prior year claims.

Recently Issued Accounting Standards

See Note 1 of Notes to unaudited condensed consolidated financial statements for a discussion of the impact 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~~Reduced demand for crude 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 ~~recovered to reach a third quarter 2021 high of $75.54 per barrel on September 27, 2021. In response~~refined products related to the ~~rapid decline~~COVID-19 pandemic led to a significant

reduction in ~~commodity~~crude oil prices ~~E&P companies acted swiftly to reduce~~and demand for drilling and completion ~~activity starting late~~services in 2020 and early 2021. However, market fundamentals are now strong, as demand is increasing for drilling and completions equipment and services, and industry supply remains constrained. Oil prices averaged $108.72 per barrel in the second quarter of 2022, as compared to $94.45 per barrel in the first quarter of 2020. While oil prices and demand for our services have recovered in 2021, our average number of rigs operating remains well below the number of our available rigs, and a significant portion of our pressure pumping horsepower remains stacked. Oil prices averaged $70.58 per barrel in the third quarter of 2021.2022.

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

We may be exposed to certain market risks arising from the use of financial instruments in the ordinary course of business. For quantitative and qualitative disclosures about market risk, see Part II, Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” in our Annual Report on Form 10-K for the year ended December 31, 2021. There have been no material changes in our exposure to market risk

As of ~~September~~June 30, ~~2021,~~2022, we had exposure to interest rate market risk associated with ~~our~~ borrowings that we had under the ~~Term Loan~~Credit 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 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, 2021, the applicable margin on LIBOR rate loans and base rate loans was 1.375% and 0.375%, respectively. As of September 30, 2021, we had $50 million in borrowings outstanding under the Term Loan Agreement at a LIBOR-based interest rate of 1.46%. ~~A one percent increase in the interest rate on the borrowings outstanding under the Term Loan Agreement as of September 30, 2021 would increase our annual cash interest expense by $0.5 million.~~

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~~June 30, ~~2021, the~~2022, applicable margin on LIBOR rate loans was 1.75% and the applicable margin on base rate loans was 0.75%. As of ~~September~~June 30, ~~2021,~~2022, we had ~~no borrowings~~$25.0 million outstanding under our revolving credit ~~facility.~~facility at a base rate of 5.5%. 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~~June 30, ~~2021,~~2022, no amounts had been disbursed under any letters of credit.

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~~June 30, ~~2021.~~2022.

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.

4037

PART II — OTHER INFORMATION

ITEM 1. Legal Proceedings

~~ITEM 1A.~~ ~~Risk Factors~~

The business relationships of our company and Pioneer may be subject to disruption due to uncertainty associated with the Pioneer acquisition and a sale of some or all of the Pioneer production services business, which could have an adverse effect on our results of operations, cash flows and fin~~ancial position.~~

Parties with which we or Pioneer do business may experience uncertainty associated with the Pioneer acquisition and a sale of some or all of the Pioneer production services business, including with respect to current or future business relationships with us following the acquisition. Our and Pioneer’s business relationships may be subject to disruption as customers, distributors, suppliers, vendors, landlords and other business partners may attempt to delay or defer entering into new business relationships, negotiate changes in or terminate existing business relationships or consider entering into business relationships with parties other than us following the acquisition. In addition, some customers may not wish to source a larger percentage of their needs from a single company or may feel that we are too closely allied with one of their competitors. Such disruptions could have an adverse effect on our results of operations, cash flows and financial position, regardless of whether a sale of some or all of the Pioneer production services business is completed, as well as a material and adverse effect on our ability to realize the expected cost savings and other benefits of the acquisition.

~~We may be unable to integrate the business of Pioneer successfully or realize the anticipated benefits of the Pioneer acquisition.~~

The Pioneer acquisition involves the combination of two companies that previously operated as independent public companies. The combination of two independent businesses is complex, costly and time consuming, and we will be required to devote significant management attention and resources to integrating Pioneer’s business practices and operations into ours. Potential difficulties that we may encounter as part of the integration process include the following:



our inability to successfully combine the business of Pioneer in a manner that permits us to achieve, on a timely basis or at all, the enhanced revenue opportunities and cost savings and other benefits anticipated to result from the Pioneer acquisition;



complexities associated with managing the combined businesses, including difficulty addressing possible differences in operational philosophies and the challenge of integrating complex systems, technology, networks and other assets of each of the companies in a seamless manner that minimizes any adverse impact on customers, suppliers, employees and other constituencies;



~~the assumption of contractual obligations with less favorable or more restrictive terms; and~~



~~potential unknown liabilities and unforeseen increased expenses or delays associated with the acquisition.~~

~~In addition, we and Pioneer have previously operated independently. It is possible that the integration process could result in:~~



~~diversion of the attention of our management; and~~



~~the disruption of, or the loss of momentum in, our ongoing businesses or inconsistencies in standards, controls, procedures and policies.~~

Any of these issues could adversely affect our ability to maintain relationships with customers, suppliers, employees and other constituencies or achieve the anticipated benefits of the Pioneer acquisition, or could reduce our earnings or otherwise adversely affect our business and financial results.

~~The synergies attributable to the Pioneer acquisition may vary from expectations.~~

We may fail to realize the anticipated benefits and synergies expected from the Pioneer acquisition, which could adversely affect our business, financial condition and operating results. The success of the acquisition will depend, in part, on our ability to successfully

integrate the acquired business and realize the anticipated strategic benefits and synergies from the combination. The anticipated benefits of the transaction may not be realized fully or at all, or may take longer to realize than expected. Actual operating, technological, strategic and revenue opportunities, if achieved at all, may be less significant than expected or may take longer to achieve than anticipated. In addition, we may not be able to sell some or all of the Pioneer production services business on terms we find acceptable in a timely manner or at all. If we are not able to achieve these objectives and realize the anticipated benefits and synergies expected from the Pioneer acquisition within the anticipated timing or at all, our business, financial condition and operating results may be adversely affected.

~~Our future results will suffer if we do not effectively manage our expanded operations.~~

The size, complexity and geographic footprint of our business have increased as a result of the Pioneer acquisition. Our operations have expanded, including internationally into Colombia. Our future success will depend, in part, upon our ability to manage this expanded business, which may pose substantial challenges for management, including challenges related to the management and monitoring of new operations and geographies and associated increased costs and complexity. We may also face increased scrutiny from governmental authorities as a result of the increase in the size of our business. There can be no assurances that we will be successful or that we will realize the expected operating efficiencies, cost savings, revenue enhancements or other benefits currently anticipated from the Pioneer acquisition.

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~~June 30, ~~2021.~~2022.

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 2021

5,559

$
9.36

—

$
130,000

August 2021

—

—

—

$
130,000

September 2021

—

—

—

$
130,000

Total

5,559

—


							Approximate Dollar
					Total Number of		Value of Shares
					Shares (or Units)		That May Yet Be
					Purchased as Part		Purchased Under the
	Total		Average Price		of Publicly		Plans or
	Number of Shares		Paid per		Announced Plans		Programs (in
Period Covered	Purchased (1)		Share		or Programs		thousands) (2)
April 2022		1,178,830	$	16.45		—	$	130,000
May 2022		—	$	—		—	$	130,000
June 2022		195,427	$	19.75		—	$	130,000
Total		1,374,257				—

(1)

We withheld ~~5,559~~1,371,230 shares during the ~~third~~second quarter of ~~2021~~2022 with respect to exercise price and employees’ tax withholding obligations upon the exercise of stock options and employees’ tax withholding obligations upon the settlement of performance unit awards and 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 (the “2014 Plan”) and the Patterson-UTI Energy, Inc. 2021 Long-Term Incentive Plan (the “2021 Plan”), and not pursuant to the stock buyback program.

(2)

On September 9, 2013, we announced that our Board of Directors approved a stock buyback program authorizing purchases of up to $200 million of our common stock in open market or privately negotiated transactions. On July 26, 2018, we announced that our Board of Directors approved an increase of the authorization under the stock buyback program to allow for $250 million of future share repurchases. On February 7, 2019, we announced that our Board of Directors approved another increase of the authorization under the stock buyback program to allow for $250 million of future share repurchases.program. On July 25, 2019, we announced that our Board of Directors ~~approved another increase of~~increased the ~~authorization~~amount authorized to be repurchased under the ~~stock buyback~~ program to ~~allow for~~up to $250 million of ~~future share repurchases.~~our common stock. 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.

4238

ITEM 6. Exhibits

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


2.1		Agreement and Plan of Merger, dated July 5, 2021, among Patterson-UTI Energy, Inc., Crescent Merger Sub Inc., Crescent Ranch Second Merger Sub LLC, and Pioneer Energy Services Corp. (incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K filed on July 6, 2021).

2.2		Amendment No. 1 to Agreement and Plan of Merger, dated September 13, 2021, among Patterson-UTI Energy, Inc., Crescent Merger Sub Inc., Crescent Ranch Second Merger Sub LLC, and Pioneer Energy Services Corp. (incorporated by reference to Exhibit 2.2 to our Current Report on Form 8-K filed on October 4, 2021).

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).

~~3.4~~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).

~~3.5~~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).

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~~June 30, ~~2021,~~2022, has been formatted in Inline XBRL.

* filed herewith

4339

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: ~~November~~August 2, ~~2021~~2022

4440


	September 30, 2021			December 31, 2020
Term Loan Agreement (Maturing June 2022) (1)	$	50,000		$	50,000
3.95% Senior Notes		509,505			509,505
5.15% Senior Notes		349,250			349,250
		908,755			908,755
Less deferred financing costs and discounts		(6,651	)		(7,271	)
Total	$	902,104		$	901,484


	Three Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2021			2020
Contract drilling	$	(51,830	)	$	(47,214	)	$	(158,680	)	$	(481,974	)
Pressure pumping		(13,774	)		(30,856	)		(77,434	)		(134,896	)
Directional drilling		(4,581	)		(9,912	)		(14,614	)		(34,892	)
Other operations		(1,335	)		(6,421	)		(9,178	)		(35,547	)
Corporate		(18,489	)		(20,163	)		(57,040	)		(80,751	)
	$	(90,009	)	$	(114,566	)	$	(316,946	)	$	(768,060	)