UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended June 30, 2021

or

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

For the transition period from                     to
Commission file number 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.

189,028,779 shares of common stock, $0.01 par value, as of July 28, 2021

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

	PART I — FINANCIAL INFORMATION
		Page
ITEM 1.	Financial Statements
	Unaudited condensed consolidated balance sheets	3
	Unaudited condensed consolidated statements of operations	4
	Unaudited condensed consolidated statements of comprehensive loss	5
	Unaudited condensed consolidated statements of changes in stockholders’ equity	6
	Unaudited condensed consolidated statements of cash flows	7
	Notes to unaudited condensed consolidated financial statements	8
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	42
ITEM 4.	Controls and Procedures	42
	PART II — OTHER INFORMATION
ITEM 1.	Legal Proceedings	43
ITEM 1A.	Risk Factors	43
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	46
ITEM 6.	Exhibits	47
Signature

PART I — FINANCIAL INFORMATION

ITEM 1. Financial Statements

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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited, in thousands, except share data)

	June 30,			December 31,
	2021			2020
ASSETS
Current assets:
Cash and cash equivalents	$	216,682		$	224,915
Accounts receivable, net of allowance for credit losses of $10,838 and $10,842    at June 30, 2021 and December 31, 2020, respectively		196,654			160,214
Federal and state income taxes receivable		72			4,428
Inventory		33,763			33,085
Other		60,929			55,314
Total current assets		508,100			477,956
Property and equipment, net		2,511,977			2,761,041
Right of use asset		16,312			16,850
Intangible assets		24,057			30,087
Deposits on equipment purchases		1,599			1,716
Other		11,261			11,419
Total assets	$	3,073,306		$	3,299,069
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	120,853		$	91,622
Accrued liabilities		166,295			175,004
Lease liability		6,334			7,096
Total current liabilities		293,482			273,722
Long-term lease liability		17,150			19,118
Long-term debt, net of debt discount and issuance costs of $6,859 and $7,271    at June 30, 2021 and December 31, 2020, respectively		901,896			901,484
Deferred tax liabilities, net		40,603			77,676
Other		12,458			11,010
Total liabilities		1,265,589			1,283,010
Commitments and contingencies (see Note 9)
Stockholders' equity:
Preferred stock, par value $0.01; authorized 1,000,000 shares, no shares issued		—			—
Common stock, par value $0.01; authorized 400,000,000 shares with 272,835,137    and 271,028,688 issued and 189,004,150 and 187,626,366 outstanding at    June 30, 2021 and December 31, 2020, respectively		2,728			2,710
Additional paid-in capital		2,914,043			2,902,236
Retained earnings		254,696			472,014
Accumulated other comprehensive income		6,085			5,412
Treasury stock, at cost, 83,830,987 and 83,402,322 shares at    June 30, 2021 and December 31, 2020, respectively		(1,369,835	)		(1,366,313	)
Total stockholders' equity		1,807,717			2,016,059
Total liabilities and stockholders' equity	$	3,073,306		$	3,299,069

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

3

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited, in thousands, except per share data)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2021			2020			2021			2020
Operating revenues:
Contract drilling	$	141,732		$	171,134		$	275,233		$	438,498
Pressure pumping		111,991			59,533			187,830			184,640
Directional drilling		24,869			11,742			44,539			46,227
Other		13,182			7,971			25,101			26,942
Total operating revenues		291,774			250,380			532,703			696,307
Operating costs and expenses:
Contract drilling		100,134			87,127			179,512			250,547
Pressure pumping		102,320			56,268			178,830			171,123
Directional drilling		22,370			12,265			39,007			44,594
Other		10,409			9,086			20,635			25,110
Depreciation, depletion, amortization and impairment		144,037			173,085			296,919			359,882
Impairment of goodwill		—			—			—			395,060
Selling, general and administrative		23,555			23,991			46,113			54,337
Merger and integration expenses		1,148			—			1,148			—
Credit loss expense		—			4,551			—			5,606
Restructuring expenses		—			38,338			—			38,338
Other operating expenses, net		(2,789	)		4,753			(2,524	)		5,204
Total operating costs and expenses		401,184			409,464			759,640			1,349,801
Operating loss		(109,410	)		(159,084	)		(226,937	)		(653,494	)
Other income (expense):
Interest income		20			334			159			991
Interest expense, net of amount capitalized		(10,704	)		(10,984	)		(20,713	)		(22,208	)
Other		812			85			826			170
Total other expense		(9,872	)		(10,565	)		(19,728	)		(21,047	)
Loss before income taxes		(119,282	)		(169,649	)		(246,665	)		(674,541	)
Income tax benefit		(15,973	)		(19,317	)		(36,943	)		(89,487	)
Net loss	$	(103,309	)	$	(150,332	)	$	(209,722	)	$	(585,054	)
Net loss per common share:
Basic	$	(0.55	)	$	(0.81	)	$	(1.12	)	$	(3.10	)
Diluted	$	(0.55	)	$	(0.81	)	$	(1.12	)	$	(3.10	)
Weighted average number of common shares outstanding:
Basic		188,408			186,633			188,044			188,654
Diluted		188,408			186,633			188,044			188,654
Cash dividends per common share	$	0.02		$	0.02		$	0.04		$	0.06

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

4

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(unaudited, in thousands)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2021			2020			2021			2020
Net loss	$	(103,309	)	$	(150,332	)	$	(209,722	)	$	(585,054	)
Other comprehensive income (loss), net of taxes of $0 for all periods:
Foreign currency translation adjustment		255			695			673			(691	)
Total comprehensive loss	$	(103,054	)	$	(149,637	)	$	(209,049	)	$	(585,745	)

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

5

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

(unaudited, in thousands)

	Common Stock				Additional						Accumulated Other
	Number of				Paid-in			Retained			Comprehensive		Treasury
	Shares		Amount		Capital			Earnings			Income (Loss)		Stock			Total
Balance, December 31, 2020		271,029	$	2,710	$	2,902,236		$	472,014		$	5,412	$	(1,366,313	)	$	2,016,059
Net loss		—		—		—			(106,413	)		—		—			(106,413	)
Foreign currency translation adjustment		—		—		—			—			418		—			418
Vesting of restricted stock units		163		2		(2	)		—			—		—			—
Stock-based compensation		—		—		5,891			—			—		—			5,891
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	)
Dividend equivalents		—		—		—			(18	)		—		—			(18	)
Purchase of treasury stock		—		—		—			—			—		(3,522	)		(3,522	)
Balance, June 30, 2021		272,835	$	2,728	$	2,914,043		$	254,696		$	6,085	$	(1,369,835	)	$	1,807,717

	Common Stock				Additional						Accumulated Other
	Number of				Paid-in			Retained			Comprehensive			Treasury
	Shares		Amount		Capital			Earnings			Income (Loss)			Stock			Total
Balance, December 31, 2019		269,372	$	2,694	$	2,875,680		$	1,294,902		$	5,478		$	(1,345,134	)	$	2,833,620
Net loss		—		—		—			(434,722	)		—			—			(434,722	)
Foreign currency translation adjustment		—		—		—			—			(1,386	)		—			(1,386	)
Vesting of restricted stock units		151		1		(1	)		—			—			—			—
Stock-based compensation		—		—		9,160			—			—			—			9,160
Payment of cash dividends ($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
Net loss		—		—		—			(150,332	)		—			—			(150,332	)
Foreign currency translation adjustment		—		—		—			—			695			—			695
Vesting of restricted stock units		1,046		11		(11	)		—			—			—			—
Stock-based compensation		—		—		4,335			—			—			—			4,335
Payment of cash dividends ($0.02 per share)		—		—		—			(3,735	)		—			—			(3,735	)
Dividend equivalents		—		—		—			(73	)		—			—			(73	)
Purchase of treasury stock		—		—		—			—			—			(910	)		(910	)
Balance, June 30, 2020		270,569	$	2,706	$	2,889,163		$	698,286		$	4,787		$	(1,366,069	)	$	2,228,873

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

6

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited, in thousands)

	Six Months Ended
	June 30,
	2021			2020
Cash flows from operating activities:
Net loss	$	(209,722	)	$	(585,054	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, amortization and impairment		296,919			359,882
Impairment of goodwill		—			395,060
Dry holes and abandonments		171			1,238
Deferred income tax benefit		(37,073	)		(87,219	)
Stock-based compensation expense		11,825			13,495
Net gain on asset disposals		(4,052	)		(2,461	)
Net gain on insurance reimbursement		—			(4,172	)
Writedown of capacity reservation contract		—			9,207
Credit loss expense		—			5,606
Restructuring expenses, non-cash		—			30,886
Amortization of debt discount and issuance costs		412			447
Changes in operating assets and liabilities:
Accounts receivable		(36,438	)		176,072
Income taxes receivable/payable		4,369			(2,663	)
Inventory and other assets		(6,423	)		16,923
Accounts payable		34,465			(65,915	)
Accrued liabilities		(8,785	)		(37,237	)
Other liabilities		(1,471	)		(4,762	)
Net cash provided by operating activities		44,197			219,333
Cash flows from investing activities:
Purchases of property and equipment		(56,573	)		(121,601	)
Proceeds from disposal of assets and insurance claims		15,145			7,265
Other		(223	)		—
Net cash used in investing activities		(41,651	)		(114,336	)
Cash flows from financing activities:
Purchases of treasury stock		(3,522	)		(20,935	)
Dividends paid		(7,523	)		(11,364	)
Debt issuance costs		—			(145	)
Net cash used in financing activities		(11,045	)		(32,444	)
Effect of foreign exchange rate changes on cash		266			43
Net increase (decrease) in cash and cash equivalents		(8,233	)		72,596
Cash and cash equivalents at beginning of period		224,915			174,185
Cash and cash equivalents at end of period	$	216,682		$	246,781
Supplemental disclosure of cash flow information:
Net cash received (paid) during the period for:
Interest, net of capitalized interest of $56 in 2021 and $406 in 2020	$	(20,604	)	$	(21,482	)
Income taxes		4,226			(402	)
Non-cash investing and financing activities:
Receivable from property and equipment insurance	$	—		$	6,983
Net decrease in payables for purchases of property and equipment		(5,232	)		(36,894	)
Net decrease in deposits on equipment purchases		117			1,390

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

7

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Basis of Presentation

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

The unaudited interim condensed consolidated financial statements have been prepared by us pursuant to the rules and regulations of the United States Securities and Exchange Commission (“SEC”). Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) have been omitted pursuant to such rules and regulations, although we believe the disclosures included either on the face of the financial statements or herein are sufficient to make the information presented not misleading. In the opinion of management, all recurring adjustments considered necessary for a fair statement of the information in conformity with U.S. GAAP have been included. The unaudited condensed consolidated balance sheet as of December 31, 2020, 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. The results of operations for the six months ended June 30, 2021 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 2.

In August 2018, the FASB issued an accounting standards update to align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The capitalized implementation costs of a hosting arrangement that is a service contract will be expensed over the term of the hosting arrangement. We adopted this new guidance on January 1, 2020 prospectively with respect to all implementation costs incurred after the date of adoption. There was no material impact on our consolidated financial statements.

In August 2018, the FASB issued an accounting standards update to eliminate certain disclosure requirements for fair value measurements for all entities, require public entities to disclose certain new information and modify certain disclosure requirements. The FASB developed the amendments to Topic 820 as part of its broader disclosure framework project, which aims to improve the effectiveness of disclosures in the notes to financial statements by focusing on requirements that clearly communicate the most important information to users of the financial statements. We adopted this new guidance on January 1, 2020 and there was no material impact on our consolidated financial statements.

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

8

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.

2. Credit Losses

ASC Topic 326 Current Expected Credit Losses (CECL)

On January 1, 2020, we adopted ASU 2016-13 Financial Instruments – Credit Losses (Topic 326) Measurement of Credit Losses on Financial Instruments, which introduces a new model to measure all expected credit losses for financial instruments held at the reporting date based on historical experience, current conditions and reasonable and supportable forecasts. Our customers are primarily oil and natural gas exploration and production companies, which are collectively exposed to oil and natural gas commodity price risk. Our customers require services from us at various stages of the exploration and production process. Accordingly, we have aggregated our trade receivables by segment. Any customers that have experienced a deterioration in credit quality are removed from the pool and evaluated individually. We utilized an accounts receivable aging schedule and historical credit loss information to estimate expected credit losses. Due to the significant decline in crude oil prices during the quarter ended March 31, 2020 and its related impact to our customers, we increased our historical credit loss rates used to determine our March 31, 2020 allowance for credit losses in the first quarter of 2020. We continued to monitor and evaluate our expected credit losses using these increased credit loss rates for the three and six months ended June 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 no credit loss expense during the three and six months ended June 30, 2021.

3. Revenues

ASC Topic 606 Revenue from Contracts with Customers

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

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

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

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

9

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.  

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 $194 million and $158 million as of June 30, 2021 and December 31, 2020, 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 six months ended June 30, 2021, no such payments were amortized and recorded in drilling revenue.  During the six months ended June 30, 2020, approximately $0.1 million was amortized and recorded in drilling revenue.

Total contract liability balances were $0.5 million and $0.6 million as of June 30, 2021 and December 31, 2020, respectively. Contract liability balances are included in “Accounts payable” and “Accrued liabilities” in the condensed consolidated balance sheets.

Contract Costs

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

Recognition of Revenue from Performance Obligations Satisfied in a Prior Period

During the six months ended June 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.

10

4. Inventory

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

	June 30, 2021		December 31, 2020
Finished goods	$	315	$	600
Work-in-process		424		802
Raw materials and supplies		33,024		31,683
Inventory	$	33,763	$	33,085

5. Property and Equipment

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

	June 30, 2021			December 31, 2020
Equipment	$	7,578,343		$	7,647,451
Oil and natural gas properties		227,966			222,738
Buildings		184,921			193,503
Land		24,562			25,781
Total property and equipment		8,015,792			8,089,473
Less accumulated depreciation, depletion and impairment		(5,503,815	)		(5,328,432	)
Property and equipment, net	$	2,511,977		$	2,761,041

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 no impairment related to the marketability or condition of our drilling rigs during the three months and six months ended June 30, 2021.

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.

6. Goodwill and 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 no goodwill balance as of June 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.

11

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

	June 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	$	(686	)	$	1,114	$	28,000	$	(26,757	)	$	1,243
Developed technology		55,772		(33,580	)		22,192		55,772		(27,515	)		28,257
Internal use software		1,130		(379	)		751		906		(319	)		587
	$	58,702	$	(34,645	)	$	24,057	$	84,678	$	(54,591	)	$	30,087

Amortization expense on intangible assets of approximately $3.1 million and $5.3 million was recorded in the three months ended June 30, 2021 and 2020, respectively. Amortization expense on intangible assets of approximately $6.3 million and $10.6 million was recorded in the six months ended June 30, 2021 and 2020, respectively.

7. Accrued Liabilities

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

	June 30, 2021		December 31, 2020
Salaries, wages, payroll taxes and benefits	$	35,316	$	37,627
Workers' compensation liability		62,179		70,847
Property, sales, use and other taxes		18,559		10,666
Insurance, other than workers' compensation		7,427		8,462
Accrued interest payable		10,636		11,325
Accrued restructuring expenses		8,314		14,310
Other		23,864		21,767
Accrued liabilities	$	166,295	$	175,004

12

8. Long-Term Debt

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

	June 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		(6,859	)		(7,271	)
Total	$	901,896		$	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.

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 June 30, 2021, we had $50 million in borrowings remaining outstanding under the Term Loan Agreement at a LIBOR-based interest rate of 1.48%. 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 June 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 June 30, 2021.

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

13

The Credit Agreement is a committed senior unsecured revolving credit facility that permits aggregate borrowings of up to $600 million, including a letter of credit facility that, at any time outstanding, is limited to $150 million and a swing line facility that, at any time outstanding, is limited to $20 million. Subject to customary conditions, we may request that the lenders’ aggregate commitments be increased by up to $300 million, not to exceed total commitments of $900 million. The original maturity date under the Credit Agreement was March 27, 2023. On March 26, 2019, we entered into Amendment No. 1 to Amended and Restated Credit Agreement, which amended the Credit Agreement to, among other things, extend the maturity date under the Credit Agreement from March 27, 2023 to March 27, 2024. On March 27, 2020, we entered into Amendment No. 2 to Amended and Restated Credit Agreement (“Amendment No. 2”) to, among other things, extend the maturity date for $550 million of revolving credit commitments of certain lenders under the Credit Agreement from March 27, 2024 to March 27, 2025. We have the option, subject to certain conditions, to exercise 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 June 30, 2021, the 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 June 30, 2021.

As of June 30, 2021, we had no borrowings outstanding under our revolving credit facility. We had $0.1 million in letters of credit outstanding under the Credit Agreement at June 30, 2021 and, as a result, had available borrowing capacity of approximately $600 million at that date.

2015 Reimbursement Agreement — On March 16, 2015, we entered into a Reimbursement Agreement (the “Reimbursement Agreement”) with The Bank of Nova Scotia (“Scotiabank”), pursuant to which we may from time to time request that Scotiabank issue an unspecified amount of letters of credit. As of June 30, 2021, we had $63.6 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.

14

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. The 2028 Notes will mature on February 1, 2028. The 2028 Notes bear interest at a rate of 3.95% per annum.

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

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

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% 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.

15

Interest expense related to the amortization of debt issuance costs was approximately $0.3 million and $0.2 million for the three months ended June 30, 2021 and 2020, respectively, and $0.5 million for the six months ended June 30, 2021 and 2020, respectively.

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

Year ending December 31,
2021	$	—
2022		50,000
2023		—
2024		—
2025		—
Thereafter		858,755
Total	$	908,755

9. Commitments and Contingencies

As of June 30, 2021, we maintained letters of credit in the aggregate amount of $63.7 million primarily for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under the terms of the underlying insurance contracts. These letters of credit expire annually at various times during the year and are typically renewed. As of June 30, 2021, no amounts had been drawn under the letters of credit.

As of June 30, 2021, we had commitments to purchase major equipment totaling approximately $53.0 million for our drilling, pressure pumping, directional drilling and oilfield rentals businesses.

Our pressure pumping business has entered into agreements to purchase minimum quantities of proppants and chemicals from certain vendors. The agreements expire in years 2021 and 2022. As of June 30, 2021, the remaining minimum obligation under these agreements was approximately $8.4 million, of which approximately $6.9 million and $1.5 million relate to the remainder of 2021 and 2022, 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.

10. Stockholders’ Equity

Stockholder Rights Agreement — On April 22, 2020, our Board of Directors adopted a stockholder rights agreement and declared a dividend of one right (a “Right”) for each outstanding share of our common stock to stockholders of record at the close of business on May 8, 2020. Each Right 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 July 28, 2021, our Board of Directors approved a cash dividend on our common stock in the amount of $0.02 per share to be paid on September 16, 2021 to holders of record as of September 2, 2021. 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.

16

Share Repurchase and Acquisitions — On September 6, 2013, our Board of Directors approved a stock buyback program that authorized purchases of up to $200 million of our common stock in open market or privately negotiated transactions. 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. All purchases executed to date have been through open market transactions. Purchases under the program are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Purchases may be made at any time without prior notice. There is no expiration date associated with the buyback program. As of June 30, 2021, 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 six months ended June 30, 2021 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		428,665		3,522
Treasury shares at end of period		83,830,987	$	1,369,835

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. No options were granted during the six months ended June 30, 2021 or 2020.

Stock option activity from January 1, 2021 to June 30, 2021 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 June 30, 2021		3,750,150		$	20.92
Exercisable at June 30, 2021		3,735,150		$	20.93

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.

17

Restricted stock unit activity from January 1, 2021 to June 30, 2021 follows:

						Weighted
						Average Grant
	Time			Performance		Date Fair Value
	Based			Based		Per Share
Non-vested restricted stock units outstanding at January 1, 2021		2,741,548			359,315	$	9.52
Granted		1,797,875			—	$	8.32
Vested		(1,185,049	)		—	$	10.14
Forfeited		(85,572	)		—	$	11.29
Non-vested restricted stock units outstanding at June 30, 2021		3,268,802			359,315	$	8.68

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 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 2021, the peer group also includes three market indices. These goals are considered to be market conditions under the relevant accounting standards and the market conditions were factored into the determination of the fair value of the respective Performance Units. Under 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 55^th percentile. If our total shareholder return during the performance period, when compared to the peer group, is at the 75^th percentile or higher, then the recipients will receive two times the target number of shares. If our total shareholder return during the performance period, when compared to the peer group, is at the 25^th percentile, then the recipients will only receive one-half of the target number of shares. If our total shareholder return during the performance period, when compared to the peer group, is between the 25^th and 55^th percentile, or the 55^th and 75^th percentile, then the shares to be received by the recipients will be determined using linear interpolation for levels of achievement between these points.

Under 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.

The total target number of shares with respect to the Performance Units for the awards granted in 2017-2021 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

In April 2021, 621,400 shares were issued to settle the 2018 Performance Units. The Performance Units granted in 2019, 2020 and 2021 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

18

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 June 30, 2021	$	602	$	69	$	830	NA		NA
Three months ended June 30, 2020	NA		$	69	$	830	$	667	$	161
Six months ended June 30, 2021	$	602	$	138	$	1,660	$	667	NA
Six months ended June 30, 2020	NA		$	69	$	1,660	$	1,334	$	642

Phantom Units — In May 2020, the Compensation Committee approved a grant of long-term performance-based phantom units to our Chief Executive Officer and President, William A. Hendricks, Jr (the “Phantom Units”). The Phantom Units were granted outside of the 2014 Plan. Pursuant to this phantom unit grant, Mr. Hendricks may earn from 0% to 200% of a target award of 298,500 phantom units based on our achievement of the same performance conditions over the same Performance Period that applies to the Performance Units granted in April 2020, as described above. Earned Phantom Units, if any, will be settled in 2023, following completion of the three-year Performance Period, in a cash payment equal to the number of earned phantom units multiplied by our average trading price per share over the twenty consecutive trading days ending March 31, 2023. Because the Phantom Units are cash-settled awards, they are accounted for as a liability classified award. The grant date fair value of the Phantom Units was $1.2 million. Compensation expense is recognized on a straight-line basis over the performance period, with the amount recognized fluctuating as a result of the Phantom Units being remeasured to fair value at the end of each reporting period due to their liability-award classification. We recognized $1.0 million and $0.2 million compensation expense associated with the Phantom Units during the three months ended June 30, 2021 and 2020, respectively. We recognized $1.5 million and $0.2 million for the six months ended June 30, 2021 and 2020, respectively.

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 June 30, 2021 was 13.4%, compared with 11.4% for the three months ended June 30, 2020. The higher effective income tax rate for the three months ended June 30, 2021 was primarily attributable to the non-deductible portion of the goodwill impairment 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, and also state rate changes enacted during the second quarter of 2021.  

Our effective income tax rate for the six months ended June 30, 2021 was 15.0%, compared with 13.3% for the six months ended June 30, 2020. The higher effective income tax rate for the six months ended June 30, 2021 was primarily attributable to the non-deductible portion of the goodwill impairment 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.

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 second quarter of 2021, the effective tax rate takes into consideration the estimated valuation allowance based on forecasted 2021 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.

19

13. Earnings Per Share

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

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

Diluted EPS is based on the weighted average number of common shares outstanding plus the dilutive effect of potential common shares, including stock options, non-vested shares of restricted stock, performance units and restricted stock units. The dilutive effect of stock options, performance units and 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 six months ended June 30, 2021 and 2020 as well as potentially dilutive securities excluded from the weighted average number of diluted common shares outstanding because their inclusion would have been anti-dilutive (in thousands, except per share amounts):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2021			2020			2021			2020
BASIC EPS:
Net loss attributed to common stockholders	$	(103,309	)	$	(150,332	)	$	(209,722	)	$	(585,054	)
Weighted average number of common shares outstanding, excluding    non-vested shares of restricted stock		188,408			186,633			188,044			188,654
Basic net loss per common share	$	(0.55	)	$	(0.81	)	$	(1.12	)	$	(3.10	)
DILUTED EPS:
Net loss attributed to common stockholders	$	(103,309	)	$	(150,332	)	$	(209,722	)	$	(585,054	)
Weighted average number of common shares outstanding, excluding    non-vested shares of restricted stock		188,408			186,633			188,044			188,654
Add dilutive effect of potential common shares		—			—			—			—
Weighted average number of diluted common shares outstanding		188,408			186,633			188,044			188,654
Diluted net loss per common share	$	(0.55	)	$	(0.81	)	$	(1.12	)	$	(3.10	)
Potentially dilutive securities excluded as anti-dilutive		10,361			9,101			10,361			9,101

14. Business Segments

At June 30, 2021, we had three reportable business segments: (i) contract drilling of oil and natural gas wells, (ii) pressure pumping services and (iii) directional drilling services. Each of these segments represents a distinct type of business and has a separate management team that reports to our chief operating decision maker. The results of operations in these segments are regularly reviewed by the chief operating decision maker for purposes of determining resource allocation and assessing performance.

20

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2021			2020			2021			2020
Revenues:
Contract drilling	$	142,264		$	171,476		$	275,926		$	439,316
Pressure pumping		111,991			59,533			187,830			184,640
Directional drilling		24,869			11,742			44,539			46,227
Other operations (1)		18,251			11,460			32,817			34,305
Elimination of intercompany revenues - Contract drilling (2)		(532	)		(342	)		(693	)		(818	)
Elimination of intercompany revenues - Other operations (2)		(5,069	)		(3,489	)		(7,716	)		(7,363	)
Total revenues	$	291,774		$	250,380		$	532,703		$	696,307
Income (loss) before income taxes:
Contract drilling	$	(58,229	)	$	(30,742	)	$	(106,850	)	$	(434,760	)
Pressure pumping		(23,921	)		(68,554	)		(63,660	)		(104,040	)
Directional drilling		(5,110	)		(14,385	)		(10,033	)		(24,980	)
Other operations		(3,287	)		(10,355	)		(7,843	)		(29,126	)
Corporate		(18,863	)		(30,497	)		(38,551	)		(54,982	)
Credit loss expense		—			(4,551	)		—			(5,606	)
Interest income		20			334			159			991
Interest expense		(10,704	)		(10,984	)		(20,713	)		(22,208	)
Other		812			85			826			170
Loss before income taxes	$	(119,282	)	$	(169,649	)	$	(246,665	)	$	(674,541	)
Depreciation, depletion, amortization and impairment:
Contract drilling	$	98,592		$	115,130		$	200,266		$	226,568
Pressure pumping		31,740			38,811			69,125			81,482
Directional drilling		6,594			9,677			13,091			20,098
Other operations		5,619			7,976			11,443			28,235
Corporate		1,492			1,491			2,994			3,499
Total depreciation, depletion, amortization and impairment	$	144,037		$	173,085		$	296,919		$	359,882
Capital expenditures:
Contract drilling	$	24,042		$	42,501		$	35,469		$	91,946
Pressure pumping		8,921			1,947			12,989			16,227
Directional drilling		1,219			2,044			1,323			4,052
Other operations		3,429			2,808			6,173			8,072
Corporate		439			373			619			1,304
Total capital expenditures	$	38,050		$	49,673		$	56,573		$	121,601

	June 30, 2021		December 31, 2020
Identifiable assets:
Contract drilling	$	2,162,825	$	2,315,318
Pressure pumping		440,928		486,702
Directional drilling		106,116		107,807
Other operations		88,060		88,676
Corporate (3)		275,377		300,566
Total assets	$	3,073,306	$	3,299,069

⁽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.

21

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

	June 30, 2021				December 31, 2020
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
Term Loan Agreement	$	50,000	$	50,000	$	50,000	$	50,000
3.95% Senior Notes		509,505		516,397		509,505		471,019
5.15% Senior Notes		349,250		366,655		349,250		319,560
Total debt	$	908,755	$	933,052	$	908,755	$	840,579

The fair values of the 3.95% Senior Notes at June 30, 2021 and December 31, 2020 are based on discounted cash flows associated with the notes using the 3.72% market rate of interest at June 30, 2021 and the 5.24% market rate of interest at December 31, 2020. The fair values of the 5.15% Senior Notes at June 30, 2021 and December 31, 2020 are based on discounted cash flows associated with the notes using the 4.43% market rate of interest at June 30, 2021 and the 6.42% market rate of interest at December 31, 2020. The fair value estimates of the 3.95% Senior Notes and the 5.15% Senior Notes are considered Level 1 fair value estimates in the fair value hierarchy of fair value accounting. The carrying values of the balance outstanding at June 30, 2021 under the Term Loan Agreement approximated its fair value as the instrument has a floating interest rate.

16. 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 six months ended June 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

22

17. Subsequent Event

On July 5, 2021, we and certain subsidiaries of ours entered into a merger agreement (the “Merger Agreement”) with Pioneer Energy Services Corp. (“Pioneer”), pursuant to which, upon the terms and subject to the conditions set forth therein, we will acquire Pioneer for aggregate consideration of up to 26,275,000 shares of our common stock and $30 million of cash. All Pioneer debt is being retired in connection with the transaction with a portion of such shares and cash and with Pioneer’s cash on hand determined in accordance with the Merger Agreement prior to closing.

The transaction is expected to close in the fourth quarter of 2021, subject to regulatory approvals, customary closing conditions and the approval of Pioneer’s stockholders.  

23

SPECIAL NOTE REGARDING 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 timing to consummate our proposed acquisition of Pioneer Energy Services Corp. (“Pioneer”);

• the risk that the conditions to closing of the proposed transaction may not be satisfied, that the related acquisition agreement is terminated or that the closing otherwise does not occur;

• the failure to close the proposed transaction on the anticipated terms;

• the risk that a regulatory approval, consent or authorization that may be required for the proposed transaction is not obtained in a timely manner or at all, or is obtained subject to conditions that are not anticipated;

• the occurrence of any event, change or other circumstances that could give rise to the termination of the merger agreement relating to the proposed transaction;

• the risk that we may incur significant transaction and other costs in connection with the proposed transaction in excess of those we anticipate;

• the risk related to disruption of management time from ongoing business operations due to the proposed transaction;

• the ultimate timing, outcome and results of integrating the operations of Pioneer into our Company, including the risk that Pioneer’s businesses may not be integrated successfully;

• the effects of the acquisition on us following the consummation of the proposed transaction, including our future financial condition, results of operations, strategy and plans;

• the risk that any announcements relating to the proposed transaction could have adverse effects on the market price of our common stock;

• potential adverse reactions or changes to business or employee relationships resulting from the announcement or completion of the proposed transaction;

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

• the potential for litigation related to the proposed transaction;

• 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;

24

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

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

• competition and demand for our services;

• strength and financial resources of competitors;

• utilization, margins and planned capital expenditures;

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

• operating hazards attendant to the oil and natural gas business;

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

• the ability to realize backlog;

• specialization of methods, equipment and services and new technologies, including the ability to develop and obtain satisfactory returns from new technology;

• the ability to retain management and field personnel;

• loss of key customers;

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

• cybersecurity events;

• synergies, costs and financial and operating impacts of acquisitions;

• 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.

25

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 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.

26

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

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

Our contract drilling business operates in the continental United States and, from time to time, we pursue contract drilling opportunities in other select markets. Our pressure pumping business operates primarily in Texas and the Appalachian region. We also provide a comprehensive suite of directional drilling services in most major producing onshore oil and gas basins in the United States, and we provide services that improve the statistical accuracy of horizontal wellbore placement. We have other operations through which we provide oilfield rental tools in select markets in the United States. We also service equipment for drilling contractors, and we provide electrical controls and automation to the energy, marine and mining industries, in North America and other select markets. In addition, we own and invest, as a non-operating working interest owner, in oil and natural gas assets that are primarily located in Texas and New Mexico.

During 2020, 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 to reach a second quarter 2021 high of $74.21 per barrel on June 25, 2021. In response to the rapid decline in commodity prices, E&P companies acted swiftly to reduce drilling and completion activity starting late in the first quarter of 2020. While oil prices have recovered from the lows experienced in the first half of 2020, 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 $66.19 per barrel in the second quarter of 2021.

Our average active rig count for the second quarter of 2021 was 73 rigs. This was an increase from our average active rig count for the first quarter of 2021 of 69. We expect that our rig count will average approximately 81 rigs during the third quarter and end the quarter at 83 rigs. Based on contracts currently in place, we expect an average of 37 rigs operating under term contracts (contracts with a duration of six months or more) during the third quarter of 2021 and an average of 24 rigs operating under term contracts during the twelve months ending June 30, 2022.

We ended the second quarter with nine active pressure pumping spreads compared to seven at the end of the first quarter. Our average active spread count and effective utilization for the second quarter were close to eight spreads. 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 nine active spreads in the third quarter. The pressure pumping market remains oversupplied.

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. 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 demand for premium drilling and completion services, will support higher pricing going forward.  Based on conversations with customers about increasing activity levels into 2022, we increased our 2021 capital expenditure forecast to approximately $165 million.

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.

On July 5, 2021, we and certain subsidiaries of ours entered into a merger agreement (the “Merger Agreement”) with Pioneer Energy Services Corp. (“Pioneer”), pursuant to which, upon the terms and subject to the conditions set forth therein, we will acquire Pioneer for aggregate consideration of up to 26,275,000 shares of our common stock and $30 million of cash. All Pioneer debt is being retired in connection with the transaction with a portion of such shares and cash and with Pioneer’s cash on hand determined in accordance with the Merger Agreement prior to closing

27

Pioneer provides 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. As of March 31, 2021, Pioneer’s drilling rig fleet was 100% pad-capable, with 17 AC rigs in the United States and eight SCR rigs in Colombia. Additionally, as of March 31, 2021, Pioneer owned production services assets consisting of 123 well servicing rigs and 72 wireline services units.    

The transaction is expected to close in the fourth quarter of 2021, subject to regulatory approvals, customary closing conditions and the approval of Pioneer’s stockholders.

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. We may also be impacted by delayed customer payments and payment defaults associated with customer liquidity issues and bankruptcies.

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

In addition to the dependence on oil and natural gas prices and demand for our services, we are highly impacted by operational risks, competition, labor issues, weather, the availability, from time to time, of products used in our pressure pumping business, supplier delays and various other factors that could materially adversely affect our business, financial condition, cash flows and results of operations, including as a result of the COVID-19 pandemic. Please see Item 1A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2020.

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

	Three Months Ended June 30,								Six Months Ended June 30,
	2021				2020				2021				2020
Contract drilling	$	141,732	48.6	%	$	171,134	68.3	%	$	275,233	51.7	%	$	438,498	63.0	%
Pressure pumping		111,991	38.4	%		59,533	23.8	%		187,830	35.3	%		184,640	26.5	%
Directional drilling		24,869	8.5	%		11,742	4.7	%		44,539	8.4	%		46,227	6.6	%
Other operations		13,182	4.5	%		7,971	3.2	%		25,101	4.6	%		26,942	3.9	%
	$	291,774	100.0	%	$	250,380	100.0	%	$	532,703	100.0	%	$	696,307	100.0	%

Contract Drilling

Contract drilling revenues accounted for 48.6% of our consolidated second quarter 2021 revenues and decreased 17.2% from the comparable 2020 period.

We have addressed our customers’ needs for drilling horizontal wells in shale and other unconventional resource plays by improving the capabilities of our drilling fleet during the last several years. The U.S. land rig industry refers to certain high specification rigs as “super-spec” rigs. We consider a super-spec rig to be a 1,500 horsepower, AC powered rig that has at least a 750,000 pound hookload, a 7,500-psi circulating system, and is pad capable. As of June 30, 2021, our rig fleet included 198 APEX^® rigs, of which 150 were super-spec rigs.

28

We maintain a backlog of commitments for contract drilling services under term contracts, which we define as contracts with a duration of six months or more. Our contract drilling backlog as of June 30, 2021 was approximately $210 million. Approximately 20% of the total contract drilling backlog at June 30, 2021 is reasonably expected to remain at June 30, 2022. 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, 2021. 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 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.

Pressure Pumping

Pressure pumping revenues accounted for 38.4% of our consolidated second quarter 2021 revenues and increased 88.1% from the comparable 2020 period. As of June 30, 2021, we had approximately 1.4 million horsepower in our pressure pumping fleet. The pressure pumping market remains oversupplied. In response to oversupplied market conditions, we implemented changes during the second quarter of 2020 that are intended to further streamline our operations, improve our efficiencies, and reduce our overall cost structure, while maintaining our customer service levels.

Directional Drilling

Directional drilling revenues accounted for 8.5% of our consolidated second quarter 2021 revenues and increased 111.8% from the comparable 2020 period. We provide a comprehensive suite of directional drilling services in most major producing onshore oil and gas basins in the United States. Our directional drilling services include directional drilling, measurement-while-drilling and supply and rental of downhole performance motors and wireline steering tools. We also provide services that improve the statistical accuracy of horizontal wellbore placement.

Other Operations

Other operations revenues accounted for 4.5% of our consolidated second quarter 2021 revenues and increased 65.4% from the comparable 2020 period. Our oilfield rentals business, with a fleet of premium oilfield rental tools, provides the largest revenue contribution to our other operations and provides specialized services for land-based oil and natural gas drilling, completion and workover activities.  Other operations also includes the results of our electrical controls and automation business, the results of our drilling equipment service business, and the results of our ownership, as a non-operating working interest owner, in oil and natural gas assets that are primarily located in Texas and New Mexico.

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2021			2020			2021			2020
Contract drilling	$	(58,229	)	$	(30,742	)	$	(106,850	)	$	(434,760	)
Pressure pumping		(23,921	)		(68,554	)		(63,660	)		(104,040	)
Directional drilling		(5,110	)		(14,385	)		(10,033	)		(24,980	)
Other operations		(3,287	)		(10,355	)		(7,843	)		(29,126	)
Corporate		(18,863	)		(35,048	)		(38,551	)		(60,588	)
	$	(109,410	)	$	(159,084	)	$	(226,937	)	$	(653,494	)

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

Our consolidated net loss for the second quarter of 2021 was $103 million compared to a net loss of $150 million for the second quarter of 2020.

29

Results of Operations

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

Contract Drilling	2021			2020			% Change
	(dollars in thousands)
Revenues	$	141,732		$	171,134			(17.2	)%
Direct operating costs		100,134			87,127			14.9	%
Margin (1)		41,598			84,007			(50.5	)%
Restructuring expenses		—			2,430			(100.0	)%
Other operating expenses (income), net		33			(4,155	)	NA
Selling, general and administrative		1,202			1,344			(10.6	)%
Depreciation, amortization and impairment		98,592			115,130			(14.4	)%
Operating loss	$	(58,229	)	$	(30,742	)		89.4	%
Operating days (2)		6,652			7,450			(10.7	)%
Average revenue per operating day	$	21.31		$	22.97			(7.2	)%
Average direct operating costs per operating day	$	15.05		$	11.69			28.7	%
Average margin per operating day (1)	$	6.25		$	11.28			(44.5	)%
Average rigs operating		73			82			(10.7	)%
Capital expenditures	$	24,042		$	42,501			(43.4	)%

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

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

During the second quarter of 2021, our average number of rigs operating was 73, compared to 82 in the second quarter of 2020. Our average rig revenue per operating day was $21,310 in the second quarter of 2021, compared to $22,970 in the second quarter of 2020. Our average revenue per operating day is largely dependent on the pricing terms of our rig contracts. Average revenue per operating day decreased primarily due to the absence of $8.6 million of lump sum early termination revenues recorded during the second quarter of 2020 that did not recur in the second quarter of 2021.

Total revenues decreased primarily due to a decrease in operating days and the absence of lump sum early termination revenues recorded in the second quarter of 2020 that did not recur in the second quarter of 2021.

Direct operating costs increased primarily due to reactivation costs and a lower portion of our rigs being on standby in the second quarter of 2021. Rigs on standby have very little associated cost. Additionally, direct operating costs in the second quarter of 2020 were lower due to cost reduction efforts in response to the industry downturn in 2020.

Restructuring expenses were recognized in the second quarter of 2020 and primarily related to severance costs.

Depreciation, amortization and impairment expense decreased primarily due to a decrease in capital expenditures as well as the $8.3 million write-down related to the closing of our Canadian drilling operations in the second quarter of 2020. Impairments lower our depreciable asset base, which reduces depreciation expense in subsequent periods.

The decrease in capital expenditures was primarily due to higher maintenance capital expenditures and the lag in delivery of previously ordered equipment in the second quarter of 2020 prior to the industry downturn.

30

Pressure Pumping	2021			2020			% Change
	(dollars in thousands)
Revenues	$	111,991		$	59,533			88.1	%
Direct operating costs		102,320			56,268			81.8	%
Margin (1)		9,671			3,265			196.2	%
Restructuring expenses		—			31,331			(100.0	)%
Selling, general and administrative		1,852			1,677			10.4	%
Depreciation, amortization and impairment		31,740			38,811			(18.2	)%
Operating loss	$	(23,921	)	$	(68,554	)		(65.1	)%
Average active spreads (2)		8			4			100.0	%
Effective utilization (3)		7.9			3.3			139.4	%
Fracturing jobs		105			35			200.0	%
Other jobs		206			152			35.5	%
Total jobs		311			187			66.3	%
Average revenue per fracturing job	$	1,006.36		$	1,549.71			(35.1	)%
Average revenue per other job	$	30.69		$	34.82			(11.9	)%
Average revenue per total job	$	360.10		$	318.36			13.1	%
Average direct operating costs per total job	$	329.00		$	300.90			9.3	%
Average margin per total job (1)	$	31.10		$	17.46			78.1	%
Margin as a percentage of revenues (1)		8.6	%		5.5	%		57.5	%
Capital expenditures	$	8,921		$	1,947			358.2	%

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

⁽²⁾ Average active spreads is the average number of spreads that were crewed and actively marketed during the period.

⁽³⁾ Effective utilization is calculated as total pumping days during the quarter divided by 75 days, which we consider full effective utilization for a spread for the period.

Generally, the revenues in our pressure pumping segment are most impacted by our number of fracturing jobs and the size (including whether or not we provide proppant and other materials) of those jobs, which is reflected in our average revenue per fracturing job. Direct operating costs are also most impacted by these same factors. Our average revenue per fracturing job is largely dependent on the pricing terms of our pressure pumping contracts and the size of the jobs. We completed 105 fracturing jobs during the second quarter of 2021, compared to 35 fracturing jobs in the second quarter of 2020. Our average revenue per fracturing job was $1.006 million in the second quarter of 2021, compared to $1.550 million in the second quarter of 2020. Our average revenue per total job increased due to a change in the overall composition of our job mix being more heavily weighted toward higher revenue fracturing jobs. Direct operating costs increased also as a result of the significant increase in fracturing jobs, while average direct operating costs per total job only increased at a lower percentage between the periods.

Restructuring expenses were recognized in the second quarter of 2020. These restructuring expenses included $7.3 million related to ROU asset abandonments, $3.5 million of severance costs and $20.4 million of contract termination costs.

Depreciation, amortization and impairment expense decreased due to lower cumulative capital expenditures since the second quarter of 2020, 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 the increase in maintenance capital commensurate with higher activity in the second quarter of 2021 as fracturing jobs began recovering from the depressed levels in 2020.

31

Directional Drilling	2021			2020			% Change
	(dollars in thousands)
Revenues	$	24,869		$	11,742			111.8	%
Direct operating costs		22,370			12,265			82.4	%
Margin (1)		2,499			(523	)	NA
Restructuring expenses		—			3,175			(100.0	)%
Selling, general and administrative		1,015			1,010			0.5	%
Depreciation and amortization		6,594			9,677			(31.9	)%
Operating loss	$	(5,110	)	$	(14,385	)		(64.5	)%
Capital expenditures	$	1,219		$	2,044			(40.4	)%

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

Directional drilling revenue increased by $13.1 million from the second quarter of 2020 primarily due to increased job activity. We averaged 28 jobs per day in the second quarter of 2021 as compared to 12 jobs per day in the second quarter of 2020.

Directional drilling direct operating costs increased by $10.1 million primarily due to increased job activity.

Restructuring expenses were recognized in the second quarter of 2020 and were primarily attributable to ROU asset abandonments.

Depreciation and amortization expense decreased due to lower cumulative capital expenditures since the second quarter of 2020, 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	$	13,182		$	7,971			65.4	%
Direct operating costs		10,409			9,086			14.6	%
Margin (1)		2,773			(1,115	)	NA
Restructuring expenses		—			501			(100.0	)%
Selling, general and administrative		441			763			(42.2	)%
Depreciation, depletion, amortization and impairment		5,619			7,976			(29.6	)%
Operating loss	$	(3,287	)	$	(10,355	)		(68.3	)%
Capital expenditures	$	3,429		$	2,808			22.1	%

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

Other operations revenue and direct operating costs increased by $5.2 million and $1.3 million, respectively, from the second quarter of 2020 primarily due to a $3.2 million increase in our oil and natural gas revenues as a result of favorable crude oil market prices. As a point of reference, average WTI-Cushing prices for the second quarter of 2021 were $66.19 per barrel as compared to $27.81 per barrel in the second 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. The marginal increase in direct operating costs was related to our oilfield technology business.

Restructuring expenses were recognized in the second quarter of 2020 and related to severance costs.

Depreciation, depletion, amortization and impairment decreased due to lower cumulative capital expenditures since the second quarter of 2020, which reduced our depreciable asset base as depreciation, depletion, amortization and impairment outpaced capital expenditures between the periods.

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

32

Corporate	2021			2020			% Change
	(dollars in thousands)
Selling, general and administrative	$	19,045		$	19,197			(0.8	)%
Restructuring expenses	$	—		$	901			(100.0	)%
Merger and integration expenses	$	1,148		$	—		NA
Depreciation	$	1,492		$	1,491			0.1	%
Other operating expenses (income), net
Net gain on asset disposals	$	(3,211	)	$	(1,222	)		162.8	%
Legal-related expenses and settlements		141			50			182.0	%
Research and development		248			843			(70.6	)%
Other		—			9,237			(100.0	)%
Other operating expenses (income), net	$	(2,822	)	$	8,908		NA
Credit loss expense	$	—		$	4,551			(100.0	)%
Interest income	$	20		$	334			(94.0	)%
Interest expense	$	10,704		$	10,984			(2.5	)%
Other income	$	812		$	85			855.3	%
Capital expenditures	$	439		$	373			17.7	%

Restructuring expenses were recognized in the second quarter of 2020 and were primarily attributable to severance and ROU asset abandonments.

Merger and integration expenses were recognized in the second quarter of 2021 related to the merger agreement with Pioneer Energy Services Corp., which was announced on July 6, 2021. The transaction is expected to close during the fourth quarter of 2021.

Other operating expenses (income), net includes net gains associated with the disposal of assets. Accordingly, the related gains or losses have been excluded from the results of specific segments. The majority of the net gain on asset disposals during the second quarter of 2021 reflect gains on disposals of buildings and land, while the gain on asset disposals in 2020 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 expect realizable value. The deposit related to the capacity reservation agreement has no balance remaining subsequent to the charge recorded in the second quarter of 2020.

A provision for credit losses was recognized in the second quarter of 2020 with respect to accounts receivable balances that are estimated to be uncollectible. No credit loss expense was recorded in 2021.

33

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

Contract Drilling	2021			2020			% Change
	(dollars in thousands)
Revenues	$	275,233		$	438,498			(37.2	)%
Direct operating costs		179,512			250,547			(28.4	)%
Margin (1)		95,721			187,951			(49.1	)%
Restructuring expenses		—			2,430			(100.0	)%
Other operating expenses (income), net		45			(4,155	)	NA
Selling, general and administrative		2,260			2,808			(19.5	)%
Depreciation, amortization and impairment		200,266			226,568			(11.6	)%
Impairment of goodwill		—			395,060			(100.0	)%
Operating loss	$	(106,850	)	$	(434,760	)		(75.4	)%
Operating days (2)		12,835			18,685			(31.3	)%
Average revenue per operating day	$	21.44		$	23.47			(8.6	)%
Average direct operating costs per operating day	$	13.99		$	13.41			4.3	%
Average margin per operating day (1)	$	7.46		$	10.06			(25.8	)%
Average rigs operating		71			103			(31.1	)%
Capital expenditures	$	35,469		$	91,946			(61.4	)%

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

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

Generally, the revenues in our contract drilling segment are most impacted by two primary factors: our average number of rigs operating and our average revenue per operating day. During the first half of 2021, our average number of rigs operating was 71, compared to 103 in the same period of 2020. Our average revenue per operating day is largely dependent on the pricing terms of our rig contracts. Average revenue per operating day decreased primarily due to the absence of $10.7 million of lump sum early termination revenues recorded during the six months ended June 30, 2020 that did not recur.

Revenues and direct operating costs decreased primarily due to a decrease in operating days. Additionally, revenues decreased due to the absence of lump sum early termination revenues recorded during the six months ended June 30, 2020 that did not recur. Average direct operating costs per operating day increased marginally due to a reduction in the proportion of rigs on standby and a higher concentration of fixed costs. Rigs on standby have very little associated cost.

Restructuring expenses were recognized during the six months ended June 30, 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 due to lower cumulative capital expenditures since June 30, 2020, which reduced our depreciable asset base as depreciation, amortization and impairment outpaced capital expenditures between the periods.

All of the goodwill associated with our contract drilling reporting unit was impaired during the six months ended June 30, 2020. See Note 6 of Notes to unaudited condensed consolidated financial statements for additional information.

The decrease in capital expenditures was primarily due to higher maintenance capital expenditures and the lag in delivery of previously ordered equipment in the first half of 2020 prior to the industry downturn and reduced capital expenditures in 2021 due to lower activity.

34

Pressure Pumping	2021			2020			% Change
	(dollars in thousands)
Revenues	$	187,830		$	184,640			1.7	%
Direct operating costs		178,830			171,123			4.5	%
Margin (1)		9,000			13,517			(33.4	)%
Restructuring expenses		—			31,331			(100.0	)%
Selling, general and administrative		3,535			4,744			(25.5	)%
Depreciation, amortization and impairment		69,125			81,482			(15.2	)%
Operating income (loss)	$	(63,660	)	$	(104,040	)		(38.8	)%
Average active spreads (2)		7			7			(—	)%
Effective utilization (3)		6.7			5.5			21.8	%
Fracturing jobs		176			124			41.9	%
Other jobs		406			361			12.5	%
Total jobs		582			485			20.0	%
Average revenue per fracturing job	$	994.88		$	1,413.11			(29.6	)%
Average revenue per other job	$	31.36		$	26.08			20.3	%
Average revenue per total job	$	322.73		$	380.70			(15.2	)%
Average direct operating costs per total job	$	307.27		$	352.83			(12.9	)%
Average margin per total job (1)	$	15.46		$	27.87			(44.5	)%
Margin as a percentage of revenues (1)		4.8	%		7.3	%		(34.2	)%
Capital expenditures and acquisitions	$	12,989		$	16,227			(20.0	)%

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

⁽²⁾ Average active spreads is the average number of spreads that were crewed and actively marketed during the period.

⁽³⁾ Effective utilization is calculated as total pumping days during the first half of the year divided by 150 days, which we consider full effective utilization for a spread for the period.

Generally, the revenues in our pressure pumping segment are most impacted by our number of fracturing jobs and the size (including whether or not we provide proppant and other materials) of those jobs, which is reflected in our average revenue per fracturing job. Direct operating costs are also most impacted by these same factors. Our average revenue per fracturing job is largely dependent on the pricing terms of our pressure pumping contracts. We completed 176 fracturing jobs during the first half of 2021, compared to 124 fracturing jobs in the same period of 2020. Our average revenue per fracturing job was $0.995 million in first half of 2021, compared to $1.413 million in the same period of 2020.

Revenues and direct operating costs increased marginally due to an increase in the number of fracturing and total jobs, which was partially offset by a 29.6% decrease in average revenue per fracturing job.

Restructuring expenses were recognized during the six months ended June 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 cost reduction efforts.

Depreciation, amortization and impairment expense decreased due to lower cumulative capital expenditures since June 30, 2020, which reduced our depreciable asset base as depreciation, amortization and impairment outpaced capital expenditures between the periods.

The decrease in capital expenditures was primarily due to conservative spending in the first six months of 2021 as activity levels continued to recover from the industry downturn in 2020.

35

Directional Drilling	2021			2020			% Change
	(dollars in thousands)
Revenues	$	44,539		$	46,227			(3.7	)%
Direct operating costs		39,007			44,594			(12.5	)%
Margin (1)		5,532			1,633			238.8	%
Restructuring expenses		—			3,175			(100.0	)%
Selling, general and administrative		2,474			3,340			(25.9	)%
Depreciation, amortization and impairment		13,091			20,098			(34.9	)%
Operating loss	$	(10,033	)	$	(24,980	)		(59.8	)%
Capital expenditures	$	1,323		$	4,052			(67.3	)%

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

Directional drilling revenue decreased by $1.7 million from the six months ended June 30, 2020 primarily due to lower revenue per job that was partially offset by higher activity. We averaged 25 jobs per day during the six months ended June 30, 2021 as compared to 23 jobs per day during the six months ended June 30, 2020.

Directional drilling direct operating costs decreased by $5.6 million also due primarily to decreased labor and materials costs and cost reduction efforts implemented in 2020.

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

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

Depreciation, amortization and impairment decreased due to lower cumulative capital expenditures since June 30, 2020, which reduced our depreciable asset base as depreciation, depletion, amortization and impairment outpaced capital expenditures between the periods.

The decrease in capital expenditures was primarily due to conservative spending in the first six months of 2021 as activity levels continued to recover from the industry downturn in 2020.

Other Operations	2021			2020			% Change
	(dollars in thousands)
Revenues	$	25,101		$	26,942			(6.8	)%
Direct operating costs		20,635			25,110			(17.8	)%
Margin (1)		4,466			1,832			143.8	%
Restructuring expenses		—			501			(100.0	)%
Selling, general and administrative		866			2,222			(61.0	)%
Depreciation, depletion, amortization and impairment		11,443			28,235			(59.5	)%
Operating loss	$	(7,843	)	$	(29,126	)		(73.1	)%
Capital expenditures	$	6,173		$	8,072			(23.5	)%

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

Other operations revenue decreased by $1.8 million from the six months ended June 30, 2020 primarily due to a $3.1 million decrease in the volume of services provided by our oilfield rentals business, which was partially offset by a $2.6 million increase in our oil and natural gas revenues as a result of favorable crude oil market prices. Average WTI-Cushing prices for the first six months of 2021 were $62.21 per barrel, as compared to $36.58 per barrel in the first six months of 2020.

Other operations direct operating costs decreased by $4.5 million from the six months ended June 30, 2020 primarily due to a decrease in the volume of services provided by our oilfield rentals business and cost reduction efforts.

36

Restructuring expenses were recognized during the six months ended June 30, 2020 and related to severance costs.

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

Depreciation, depletion, amortization and impairment decreased due to lower cumulative capital expenditures since June 30, 2020, which reduced our depreciable asset base as depreciation, depletion, amortization and impairment outpaced capital expenditures between the periods. Additionally, we recognized a $11.2 million impairment related to certain of our oil and natural gas assets during the six months ended June 30, 2020.

The decrease in capital expenditures was primarily due to higher maintenance capital expenditures during the six months ended June 30, 2020 when activity levels were higher and reduced capital expenditures in 2021 due to lower activity.

Corporate	2021			2020			% Change
	(dollars in thousands)
Selling, general and administrative	$	36,978		$	41,223			(10.3	)%
Restructuring expenses	$	—		$	901			(100.0	)%
Merger and integration expenses	$	1,148		$	—		NA
Depreciation	$	2,994		$	3,499			(14.4	)%
Other operating expenses (income), net
Net gain on asset disposals	$	(4,052	)	$	(2,461	)		64.6	%
Legal-related expenses and settlements		611			850			(28.1	)%
Research and development		872			1,738			(49.8	)%
Other		—			9,232			(100.0	)%
Other operating expenses (income), net	$	(2,569	)	$	9,359		NA
Credit loss expense	$	—		$	5,606			(100.0	)%
Interest income	$	159		$	991			(84.0	)%
Interest expense	$	20,713		$	22,208			(6.7	)%
Other income	$	826		$	170			385.9	%
Capital expenditures	$	619		$	1,304			(52.5	)%

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

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

Merger and integration expenses were recognized during the six months ended June 30, 2021 related to the merger agreement with Pioneer Energy Services Corp., which was announced on July 6, 2021. The transaction is expected to close during the fourth quarter of 2021.

Other operating expenses (income), net includes net gains associated with the disposal of assets. Accordingly, the related gains have been excluded from the results of specific segments. The majority of the net gain on asset disposals during the six months ended June 30, 2021 reflect gains on disposals of buildings and land, while the gain on asset disposals in 2020 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 expect realizable value. The deposit related to the capacity reservation agreement has no balance remaining subsequent to the charge recorded during the six months ended June 30, 2020.

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

Lower interest expense for the six months ended June 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.

37

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 June 30, 2021 was 13.4%, compared with 11.4% for the three months ended June 30, 2020. The higher effective income tax rate for the three months ended June 30, 2021 was primarily attributable to the non-deductible portion of the goodwill impairment 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, and also state rate changes enacted during the second quarter of 2021.  

Our effective income tax rate for the six months ended June 30, 2021 was 15.0%, compared with 13.3% for the six months ended June 30, 2020. The higher effective income tax rate for the six months ended June 30, 2021 was primarily attributable to the non-deductible portion of the goodwill impairment 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.

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 second quarter of 2021, the effective tax rate takes into consideration the estimated valuation allowance based on forecasted 2021 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.

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 June 30, 2021, we had approximately $215 million in working capital, including $217 million of cash and cash equivalents, and approximately $600 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 June 30, 2021, we had no borrowings outstanding under our revolving credit facility, and $0.1 million in letters of credit outstanding under the Credit Agreement and, as a result, had available borrowing capacity of approximately $600 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.

38

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 June 30, 2021, we had $50 million of borrowings remaining outstanding under the Term Loan Agreement at a LIBOR-based interest rate of 1.48%.

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 June 30, 2021 was $909 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 million of borrowings under the Term Loan Agreement. We were in compliance with all covenants at June 30, 2021.

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 8 of Notes to unaudited condensed consolidated financial statements.

We had $63.7 million of outstanding letters of credit at June 30, 2021, which were comprised of $63.6 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 June 30, 2021, no amounts had been drawn under the letters of credit.

Operating lease liabilities totaled $23.5 million at June 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.

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

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

• $44.2 million from operating activities, and

• $15.1 million in proceeds from the disposal of property and equipment.

During the six months ended June 30, 2021, we used $7.5 million to pay dividends on our common stock and $56.6 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,

39

• to acquire and procure equipment to support our drilling, pressure pumping, directional drilling, oilfield rentals and manufacturing operations, and

• to fund investments in oil and natural gas properties on a non-operating working interest basis.

Based on conversations with customers about increasing activity levels into 2022, we increased our 2021 capital expenditure forecast to approximately $165 million.

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

	Per Share		Total
			(in thousands)
Paid on March 18, 2021	$	0.02	$	3,754
Paid on June 17, 2021		0.02		3,769
	$	0.04	$	7,523

On July 28, 2021, our Board of Directors approved a cash dividend on our common stock in the amount of $0.02 per share to be paid on September 16, 2021 to holders of record as of September 2, 2021. 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.

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

On September 6, 2013, our Board of Directors approved a stock buyback program that authorized purchases of up to $200 million of our common stock in open market or privately negotiated transactions. 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. All purchases executed to date have been through open market transactions. Purchases under the program are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Purchases may be made at any time without prior notice. There is no expiration date associated with the buyback program. As of June 30, 2021, 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 six months ended June 30, 2021 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 (1)		428,665		3,522
Treasury shares at end of period		83,830,987	$	1,369,835

⁽¹⁾ We withheld 428,665 shares during the first two quarters of 2021 with respect to 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.

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.

40

Adjusted EBITDA

Adjusted earnings before interest, taxes, depreciation and amortization (“Adjusted EBITDA”) is not defined by accounting principles generally accepted in the United States of America (“U.S. GAAP”). We define Adjusted EBITDA as net income (loss) plus net interest expense, income tax expense (benefit) and depreciation, depletion, amortization and impairment expense (including impairment of goodwill). We present Adjusted EBITDA because we believe it provides to both management and investors additional information with respect to the performance of our fundamental business activities and a comparison of the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be construed as an alternative to the U.S. GAAP measure of net income (loss). Our computations of Adjusted EBITDA may not be the same as other similarly titled measures of other companies. Set forth below is a reconciliation of the non-U.S. GAAP financial measure of Adjusted EBITDA to the U.S. GAAP financial measure of net income (loss).

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2021			2020			2021			2020
	(in thousands)
Net loss	$	(103,309	)	$	(150,332	)	$	(209,722	)	$	(585,054	)
Income tax benefit		(15,973	)		(19,317	)		(36,943	)		(89,487	)
Net interest expense		10,684			10,650			20,554			21,217
Depreciation, depletion, amortization and impairment		144,037			173,085			296,919			359,882
Impairment of goodwill		—			—			—			395,060
Adjusted EBITDA	$	35,439		$	14,086		$	70,808		$	101,618

Critical Accounting Policies and Estimates

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

Recently Issued Accounting Standards

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

Volatility of Oil and Natural Gas Prices and its Impact on Operations and Financial Condition

Our revenue, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas and expectations about future prices. For many years, oil and natural gas prices and markets have been extremely volatile. Prices are affected by many factors beyond our control. Oil prices remain extremely volatile, as the closing price of oil (WTI-Cushing) reached a first quarter 2020 high of $63.27 per barrel on January 6, 2020, declined to negative $36.98 per barrel on April 20, 2020, and recovered to reach a second quarter 2021 high of $74.21 per barrel on June 25, 2021. In response to the rapid decline in commodity prices, E&P companies acted swiftly to reduce drilling and completion activity starting late in the first quarter of 2020. While oil prices recovered from the lows experienced in the first half of 2020, 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 $66.19 per barrel in the second quarter of 2021.

41

We expect oil and natural gas prices to continue to be volatile and to affect our financial condition, operations and ability to access sources of capital. Higher oil and natural gas prices do not necessarily result in increased activity because demand for our services is generally driven by our customers’ expectations of future oil and natural gas prices, as well as our customers’ ability to access sources of capital to fund their operating and capital expenditures. A decline in demand for oil and natural gas, prolonged low oil or natural gas prices, expectations of decreases in oil and natural gas prices or a reduction in the ability of our customers to access capital, would likely result in reduced capital expenditures by our customers and decreased demand for our services, which could have a material adverse effect on our operating results, financial condition and cash flows. Even during periods of historically moderate or high prices for oil and natural gas, companies exploring for oil and natural gas may cancel or curtail programs, or reduce their levels of capital expenditures for exploration and production for a variety of reasons, which could reduce demand for our services.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

As of June 30, 2021, we had exposure to interest rate market risk associated with our borrowings under the Term Loan Agreement, and we would have had exposure to interest rate market risk associated with any borrowings that we had under the Credit Agreement and amounts owed under the Reimbursement Agreement.

Loans under the 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 June 30, 2021, the applicable margin on LIBOR rate loans and base rate loans was 1.375% and 0.375%, respectively. As of June 30, 2021, we had $50 million in borrowings outstanding under the Term Loan Agreement at a LIBOR-based interest rate of 1.48%. A one percent increase in the interest rate on the borrowings outstanding under the Term Loan Agreement as of June 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 June 30, 2021, the applicable margin on LIBOR rate loans was 1.75% and the applicable margin on base rate loans was 0.75%. As of June 30, 2021, we had no borrowings outstanding under our revolving credit facility. The interest rate on borrowings outstanding under our revolving credit facility is variable and adjusts at each interest payment date based on our election of LIBOR or the base rate.

Under the Reimbursement Agreement, we will reimburse Scotiabank on demand for any amounts that Scotiabank has disbursed under any letters of credit. We are obligated to pay Scotiabank interest on all amounts not paid by us on the date of demand or when otherwise due at the LIBOR rate plus 2.25% per annum. As of June 30, 2021, 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 June 30, 2021.

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.

42

PART II — OTHER INFORMATION

ITEM 1. Legal Proceedings

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

ITEM 1A. Risk Factors

The obligations of both us and Pioneer to complete the Pioneer acquisition are subject to a number of conditions, which, if not fulfilled, or not fulfilled in a timely manner, may delay completion of the acquisition or result in termination of the merger agreement.

The respective obligations of each of us and Pioneer to effect the Pioneer acquisition are subject to the satisfaction of the following conditions:

•the requisite approval of the Pioneer stockholders must have been obtained;

•any waiting period (and any extension thereof) under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 relating to the acquisition shall have expired or been terminated;

•no temporary restraining order, preliminary or permanent injunction or other judgment, order or decree or other legal restraint or prohibition issued by any governmental entity having jurisdiction over any party shall be in effect, and no law shall have been enacted, entered, promulgated, enforced or deemed applicable by any governmental entity that prohibits or makes illegal consummation of the acquisition;

•the shares of our common stock to be issued in the acquisition shall have been approved for listing on the NASDAQ;

•the registration statement on Form S-4 filed in connection with the acquisition shall have been declared effective by the SEC under the Securities Act of 1933 and shall not be the subject of any stop order suspending the effectiveness of the Form S-4 and no action seeking a stop order shall have been initiated or threated by the SEC;

•the third supplemental indenture to the indenture governing the Pioneer senior notes shall have been executed and delivered by Pioneer, the guarantors party thereto and the trustee under such indenture, and shall be in full force and effect;

•subject to certain exceptions and materiality standards provided in the merger agreement, the representations and warranties of the other party must be true and correct as of the date of the merger agreement and as of the closing date; and

•the other party must have performed in all material respects all of its obligations required to be performed under the merger agreement.

Our obligations to effect the Pioneer acquisition are also subject to the satisfaction, or waiver by us, of the following additional conditions, among others:

•since the date of the merger agreement there shall not have occurred any event, change, circumstance, occurrence, effect or state of facts that, individually or in the aggregate, has had or would reasonably be expected to have a material adverse effect on Pioneer; and

•not more than 6% of the shares of Pioneer common stock outstanding as of immediately prior to the effective time shall be dissenting shares.

Many of the conditions to completion of the Pioneer acquisition are not within our control, and we cannot predict when, or if, these conditions will be satisfied. If any of these conditions are not satisfied or waived prior to January 3, 2022, it is possible that the merger agreement may be terminated. Although we have agreed in the merger agreement to use reasonable best efforts, subject to certain limitations, to complete the acquisition as promptly as practicable, these and other conditions to the completion of the acquisition may fail to be satisfied. In addition, satisfying the conditions to and completing the acquisition may take longer, and could cost more, than we expect. We cannot predict whether and when these other conditions will be satisfied. Furthermore, the requirements for obtaining the required clearances and approvals could delay the completion of the acquisition for a significant period of time or prevent them from occurring. Any delay in completing the Pioneer acquisition may adversely affect the cost savings and other benefits that we expect to achieve if the acquisition and the integration of the companies’ respective businesses are completed within the expected timeframe. There can be no assurance that all required regulatory approvals will be obtained or obtained prior to the termination date.

43

The business relationships of our company and Pioneer may be subject to disruption due to uncertainty associated with the Pioneer acquisition and our publicly announced expectation to divest the Pioneer well service rig business following the closing of the acquisition, which could have an adverse effect on the results of operations, cash flows and financial position of us or Pioneer pending and following the acquisition.

Parties with which we or Pioneer do business may experience uncertainty associated with the Pioneer acquisition and our publicly announced expectation to divest the Pioneer well service rig business following the closing of the acquisition, 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 the acquisition or the subsequent sale of the Pioneer well service rig 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. The risk, and adverse effect, of any disruption could be exacerbated by a delay in completion of the acquisition or termination of the merger agreement.

We expect to incur significant transaction costs in connection with the Pioneer acquisition, which may be in excess of those we anticipate.

We have incurred and are expected to continue to incur a number of non-recurring costs associated with negotiating and completing the Pioneer acquisition, combining the operations of the two companies and achieving desired synergies. All costs and expenses incurred in connection with the authorization, preparation, investigation, negotiation, execution and performance of the merger agreement and the transactions contemplated thereby will be paid by us, except with respect to certain Pioneer designated expenses, which will be paid by Pioneer. Our costs in connection with the Pioneer acquisition have been, and will continue to be, substantial and will be borne whether or not the acquisition is completed. We will also incur costs related to formulating and implementing integration plans, including facilities and systems consolidation costs and other employment-related costs. We will continue to assess the magnitude of these costs, and additional unanticipated costs may be incurred in connection with the acquisition and the integration of the two companies’ businesses. While we have assumed that a certain level of expenses would be incurred, there are many factors beyond our control that could affect the total amount or the timing of the expenses. The elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the businesses, may not offset integration-related costs and achieve a net benefit in the near term, or at all.

The costs described above and any unanticipated costs and expenses, which will be borne by us even if the Pioneer acquisition is not completed, could have an adverse effect on our financial condition and operating results.

Litigation relating to the Pioneer acquisition could result in an injunction preventing the completion of the acquisition and/or substantial costs to us.

Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into acquisition, merger or other business combination agreements. Even if such a lawsuit is without merit, defending against these claims can result in substantial costs and divert management time and resources. An adverse judgment could result in monetary damages, which could have a negative impact on our liquidity and financial condition.

Lawsuits that may be brought against us, Pioneer or our respective directors could also seek, among other things, injunctive relief or other equitable relief, including a request to enjoin the parties from consummating the Pioneer acquisition. One of the conditions to the closing of the acquisition is that no injunction by any court or other tribunal of competent jurisdiction has been entered and continues to be in effect and no law has been adopted or is effective, in either case that prohibits or makes illegal the closing. Consequently, if a plaintiff is successful in obtaining an injunction prohibiting completion of the acquisition, that injunction may delay or prevent the acquisition from being completed within the expected timeframe or at all, which may adversely affect our business, financial position and results of operation.

There can be no assurance that any of the defendants will be successful in the outcome of any potential future lawsuits. The defense or settlement of any lawsuit or claim that remains unresolved at the time the Pioneer acquisition is completed may adversely affect our business, financial condition, results of operations and cash flows.

44

The Pioneer acquisition may be completed even though material adverse changes subsequent to the announcement of the acquisition, such as industry-wide changes or other events, may occur.

We can refuse to complete the Pioneer acquisition if there is a material adverse change affecting Pioneer. However, some types of changes do not permit us to refuse to complete the transaction, even if such changes would have a material adverse effect on Pioneer. For example, a worsening of Pioneer’s financial condition or results of operations due to a decrease in commodity prices or general economic conditions would not give us the right to refuse to complete the acquisition. In addition, we have the ability, but are under no obligation, to waive any material adverse change that results in the failure of a closing condition and instead proceed with completing the acquisition. If adverse changes occur that affect Pioneer but we are still required or voluntarily decide to complete the transaction, our share price, business and financial results after the acquisition may suffer.

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 currently operate 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 and, until the completion of the Pioneer acquisition, will continue to operate, 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 following the acquisition.

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 significant 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 complete our publicly announced divestiture of the Pioneer well service rig 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 following the Pioneer acquisition will suffer if we do not effectively manage our expanded operations.

Following the Pioneer acquisition, the size, complexity and geographic footprint of our business will increase. Our operations will expand internationally into Colombia and, until its expected divestiture, we will operate Pioneer’s well service rig business.  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.

45

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds

The table below sets forth the information with respect to purchases of our common stock made by us during the quarter ended June 30, 2021.

							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 2021		255,650	$	6.52		—	$	130,000
May 2021		—	$	—		—	$	130,000
June 2021		173,015	$	10.72		—	$	130,000
Total		428,665				—

⁽¹⁾ We withheld 428,665 shares during the second quarter of 2021 with respect to 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 2014 Plan and 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. On July 25, 2019, we announced that our Board of Directors approved another increase of the authorization under the stock buyback program to allow for $250 million of future share repurchases. All purchases executed to date have been through open market transactions. Purchases under the program are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Purchases may be made at any time without prior notice. Shares of stock purchased under the buyback program are held as treasury shares. There is no expiration date associated with the buyback program.

46

ITEM 6. Exhibits

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

3.1	Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.1 to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).
3.2	Certificate of Amendment to Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.2 to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).
3.3	Certificate of 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	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	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).
10.1	Patterson-UTI Energy, Inc. 2021 Long-Term Incentive Plan (incorporated by reference to Annex A of our Definitive Proxy Statement on Schedule 14A, filed on April 12, 2021)
10.2*	Form of Executive Officer Restricted Stock Unit Award Agreement.
10.3*	Form of Executive Officer Share-Settled Performance Share Award Agreement.
10.4*	First Amendment to Employment Agreement, effective as April 9, 2021, by and between Patterson-UTI Energy, Inc. and William Andrew Hendricks, Jr.
10.5*	First Amendment to Employment Agreement, effective as April 9, 2021, by and between Patterson-UTI Energy, Inc. and C. Andrew Smith.
10.6*	First Amendment to Employment Agreement, effective as April 9, 2021, by and between Patterson-UTI Energy, Inc. and Seth D. Wexler.
10.7*	First Amendment to Employment Agreement, effective as April 9, 2021, by and between Patterson-UTI Energy, Inc. and James M. Holcomb.
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 June 30, 2021, has been formatted in Inline XBRL.

* filed herewith

47

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: August 3, 2021

48