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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
______________________
Form 10-Q
______________________

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

For the quarterly period ended March 31, 2025
or

o | 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 þ No o
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 þ No o
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 | þ |  | Accelerated filer | o |  | Smaller reporting company | o
Non-accelerated filer | o |  |  |  |  | Emerging growth company | o

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. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
385,987,026 shares of common stock, $0.01 par value, as of April 23, 2025.

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 income | 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 | 28
ITEM 3. | Quantitative and Qualitative Disclosures About Market Risk | 40
ITEM 4. | Controls and Procedures | 41
| PART II — OTHER INFORMATION |
ITEM 1. | Legal Proceedings | 42
ITEM 2. | Unregistered Sales of Equity Securities and Use of Proceeds | 42
ITEM 5. | Other Information | 43
ITEM 6. | Exhibits | 44
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)

| March 31, 2025 |  | December 31, 2024
ASSETS |  |  |
Current assets: |  |  |
Cash, cash equivalents and restricted cash | $ | 225,204 |  |  | $ | 241,293 |
Accounts receivable, net of allowance for credit losses of $15,493 and $15,047 at March 31, 2025 and December 31, 2024, respectively | 800,291 |  |  | 763,806 |
Inventory | 167,767 |  |  | 167,023 |
Other current assets | 124,148 |  |  | 123,193 |
Total current assets | 1,317,410 |  |  | 1,295,315 |
Property and equipment, net | 2,937,063 |  |  | 3,010,342 |
Operating lease right of use asset | 42,787 |  |  | 44,385 |
Finance lease right of use asset | 24,258 |  |  | 27,018 |
Goodwill | 487,388 |  |  | 487,388 |
Intangible assets, net | 900,959 |  |  | 929,610 |
Deposits on equipment purchases | 19,895 |  |  | 15,699 |
Other assets | 35,666 |  |  | 23,709 |
Total assets | $ | 5,765,426 |  |  | $ | 5,833,466 |
LIABILITIES AND STOCKHOLDERS’ EQUITY |  |  |
Current liabilities: |  |  |
Accounts payable | $ | 513,963 |  |  | $ | 421,318 |
Accrued liabilities | 273,678 |  |  | 385,751 |
Operating lease liability | 13,590 |  |  | 13,322 |
Finance lease liability | 13,840 |  |  | 15,214 |
Current maturities of long-term debt | 3,217 |  |  | 6,388 |
Total current liabilities | 818,288 |  |  | 841,993 |
Long-term operating lease liability | 32,060 |  |  | 34,305 |
Long-term finance lease liability | 9,187 |  |  | 10,216 |
Long-term debt, net of debt discount and issuance costs of $7,319 and $7,637 at March 31, 2025 and December 31, 2024, respectively | 1,220,083 |  |  | 1,219,770 |
Deferred tax liabilities, net | 238,512 |  |  | 238,097 |
Other liabilities | 11,891 |  |  | 13,241 |
Total liabilities | 2,330,021 |  |  | 2,357,622 |
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 800,000,000 shares with 521,755,322 and 520,784,783 issued and 385,978,013 and 387,344,755 outstanding at March 31, 2025 and December 31, 2024, respectively | 5,216 |  |  | 5,206 |
Additional paid-in capital | 6,465,885 |  |  | 6,453,606 |
Retained deficit | (1,069,875) |  |  | (1,039,338) |
Accumulated other comprehensive loss | (2,873) |  |  | (2,584) |
Treasury stock, at cost, 135,777,309 and 133,440,028 shares at March 31, 2025 and December 31, 2024, respectively | (1,971,362) |  |  | (1,951,067) |
Total stockholders’ equity attributable to controlling interests | 3,426,991 |  |  | 3,465,823 |
Noncontrolling interest | 8,414 |  |  | 10,021 |
Total equity | 3,435,405 |  |  | 3,475,844 |
Total liabilities and stockholders’ equity | $ | 5,765,426 |  |  | $ | 5,833,466 |

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 March 31, |  |
| 2025 |  | 2024 |  |  |  |
Operating revenues: |  |  |  |  |  |  |
Drilling Services | $ | 412,860 |  |  | $ | 457,573 |  |  |  |  |
Completion Services | 766,080 |  |  | 944,997 |  |  |  |  |
Drilling Products | 85,663 |  |  | 89,973 |  |  |  |  |
Other | 15,934 |  |  | 17,817 |  |  |  |  |
Total operating revenues | 1,280,537 |  |  | 1,510,360 |  |  |  |  |
Operating costs and expenses: |  |  |  |  |  |  |
Drilling Services | 247,629 |  |  | 271,737 |  |  |  |  |
Completion Services | 657,681 |  |  | 745,594 |  |  |  |  |
Drilling Products | 46,940 |  |  | 48,630 |  |  |  |  |
Other | 9,164 |  |  | 11,178 |  |  |  |  |
Depreciation, depletion, amortization and impairment | 231,866 |  |  | 274,956 |  |  |  |  |
Selling, general and administrative | 66,930 |  |  | 64,984 |  |  |  |  |
Merger and integration expense | 432 |  |  | 12,233 |  |  |  |  |
Other operating expense (income), net | 2,950 |  |  | (5,951) |  |  |  |  |
Total operating costs and expenses | 1,263,592 |  |  | 1,423,361 |  |  |  |  |
Operating income | 16,945 |  |  | 86,999 |  |  |  |  |
Other income (expense): |  |  |  |  |  |  |
Interest income | 1,464 |  |  | 2,189 |  |  |  |  |
Interest expense, net of amount capitalized | (17,697) |  |  | (18,335) |  |  |  |  |
Other income | 1,968 |  |  | 850 |  |  |  |  |
Total other expense | (14,265) |  |  | (15,296) |  |  |  |  |
Income before income taxes | 2,680 |  |  | 71,703 |  |  |  |  |
Income tax expense | 1,390 |  |  | 19,997 |  |  |  |  |
Net income | 1,290 |  |  | 51,706 |  |  |  |  |
Net income attributable to noncontrolling interest | 285 |  |  | 471 |  |  |  |  |
Net income attributable to common stockholders | $ | 1,005 |  |  | $ | 51,235 |  |  |  |  |
Net income attributable to common stockholder per common share: |  |  |  |  |  |
Basic | $ | 0.00 |  |  | $ | 0.13 |  |  |  |  |
Diluted | $ | 0.00 |  |  | $ | 0.13 |  |  |  |  |
Weighted average number of common shares outstanding: |  |  |  |  |  |  |
Basic | 386,521 |  |  | 408,182 |  |  |  |
Diluted | 387,044 |  |  | 409,819 |  |  |  |
Cash dividends per common share | $ | 0.08 |  |  | $ | 0.08 |  |  |  |  |

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 INCOME
(unaudited, in thousands)

| Three Months Ended March 31, |  |
| 2025 |  | 2024 |  |  |  |
Net income | $ | 1,290 |  |  | $ | 51,706 |  |  |  |  |
Other comprehensive loss: |  |  |  |  |  |  |
Foreign currency translation adjustment, net of taxes of $0 for all periods | (289) |  |  | (993) |  |  |  |  |
Comprehensive income | 1,001 |  |  | 50,713 |  |  |  |  |
Less: comprehensive income attributable to noncontrolling interest | 285 |  |  | 471 |  |  |  |  |
Comprehensive income attributable to common stockholders | $ | 716 |  |  | $ | 50,242 |  |  |  |  |

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 Paid-in Capital |  | Retained Deficit |  | Accumulated Other Comprehensive Loss |  | Treasury Stock |  | Noncontrolling Interest |  | Total
| Number of Shares |  | Amount |  |  |  |  |  |
Balance, December 31, 2024 | 520,785 |  | $ | 5,206 |  |  | $ | 6,453,606 |  |  | $ | (1,039,338) |  |  | $ | (2,584) |  |  | $ | (1,951,067) |  |  | $ | 10,021 |  |  | $ | 3,475,844 |
Net income | — |  | — |  |  | — |  |  | 1,005 |  |  | — |  |  | — |  |  | 285 |  |  | 1,290 |
Distributions to noncontrolling interest | — |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (1,892) |  |  | (1,892) |
Foreign currency translation adjustment | — |  | — |  |  | — |  |  | — |  |  | (289) |  |  | — |  |  | — |  |  | (289) |
Vesting of restricted stock units | 970 |  | 10 |  |  | (10) |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Stock-based compensation | — |  | — |  |  | 12,289 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 12,289 |
Payment of cash dividends ($0.08 per share) | — |  | — |  |  | — |  |  | (30,877) |  |  | — |  |  | — |  |  | — |  |  | (30,877) |
Dividend equivalents | — |  | — |  |  | — |  |  | (665) |  |  | — |  |  | — |  |  | — |  |  | (665) |
Purchase of treasury stock | — |  | — |  |  | — |  |  | — |  |  | — |  |  | (20,295) |  |  | — |  |  | (20,295) |
Balance, March 31, 2025 | 521,755 |  | $ | 5,216 |  |  | $ | 6,465,885 |  |  | $ | (1,069,875) |  |  | $ | (2,873) |  |  | $ | (1,971,362) |  |  | $ | 8,414 |  |  | $ | 3,435,405 |

| Common Stock |  | Additional Paid-in Capital |  | Retained Earnings |  | Accumulated Other Comprehensive Income (Loss) |  | Treasury Stock |  | Noncontrolling Interest |  | Total
| Number of Shares |  | Amount |  |  |  |  |  |
Balance, December 31, 2023 | 516,775 |  | $ | 5,166 |  |  | $ | 6,407,294 |  |  | $ | 57,035 |  |  | $ | 472 |  |  | $ | (1,657,675) |  |  | $ | 8,389 |  |  | $ | 4,820,681 |
Net income | — |  | — |  |  | — |  |  | 51,235 |  |  | — |  |  | — |  |  | 471 |  |  | 51,706 |
Foreign currency translation adjustment | — |  | — |  |  | — |  |  | — |  |  | (993) |  |  | — |  |  | — |  |  | (993) |
Vesting of restricted stock units | 1,363 |  | 14 |  |  | (14) |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Stock-based compensation | — |  | — |  |  | 12,051 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 12,051 |
Payment of cash dividends ($0.08 per share) | — |  | — |  |  | — |  |  | (32,553) |  |  | — |  |  | — |  |  | — |  |  | (32,553) |
Dividend equivalents | — |  | — |  |  | — |  |  | (422) |  |  | — |  |  | — |  |  | — |  |  | (422) |
Purchase of treasury stock | — |  | — |  |  | — |  |  | — |  |  | — |  |  | (98,613) |  |  | — |  |  | (98,613) |
Balance, March 31, 2024 | 518,138 |  | $ | 5,180 |  |  | $ | 6,419,331 |  |  | $ | 75,295 |  |  | $ | (521) |  |  | $ | (1,756,288) |  |  | $ | 8,860 |  |  | $ | 4,751,857 |

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)

| Three Months Ended March 31,
| 2025 |  | 2024
Cash flows from operating activities: |  |  |
Net income | $ | 1,290 |  |  | $ | 51,706 |
Adjustments to reconcile net income to net cash provided by operating activities: |  |  |
Depreciation, depletion, amortization and impairment | 231,866 |  |  | 274,956 |
Deferred income tax expense | 359 |  |  | 19,507 |
Stock-based compensation | 12,289 |  |  | 12,051 |
Net gain on asset disposals | (709) |  |  | (2,668) |
Other | (166) |  |  | 5,844 |
Changes in operating assets and liabilities: |  |  |
Accounts receivable | (36,544) |  |  | 95,119 |
Inventory | 2,046 |  |  | (10,585) |
Other current assets | 12,516 |  |  | 14,334 |
Other assets | 2,948 |  |  | 8,390 |
Accounts payable | 98,038 |  |  | 35,401 |
Accrued liabilities | (113,103) |  |  | (125,191) |
Other liabilities | (2,689) |  |  | (12,973) |
Net cash provided by operating activities | 208,141 |  |  | 365,891 |
Cash flows from investing activities: |  |  |
Purchases of property and equipment | (161,831) |  |  | (226,941) |
Proceeds from disposal of assets | 4,342 |  |  | 2,389 |
Other | (7,015) |  |  | (2,933) |
Net cash used in investing activities | (164,504) |  |  | (227,485) |
Cash flows from financing activities: |  |  |
Purchases of treasury stock | (20,295) |  |  | (97,782) |
Dividends paid | (30,877) |  |  | (32,553) |
Payments of finance leases | (2,632) |  |  | (27,229) |
Other | (5,069) |  |  | (4,025) |
Net cash used in financing activities | (58,873) |  |  | (161,589) |
Effect of foreign exchange rate changes on cash, cash equivalents and restricted cash | (853) |  |  | 750 |
Net decrease in cash, cash equivalents and restricted cash | (16,089) |  |  | (22,433) |
Cash, cash equivalents and restricted cash at beginning of period | 241,293 |  |  | 192,680 |
Cash, cash equivalents and restricted cash at end of period | $ | 225,204 |  |  | $ | 170,247 |
Supplemental disclosure of cash flow information: |  |  |
Net cash received (paid) during the period for: |  |  |
Interest, net of capitalized interest of $315 in 2025 and $216 in 2024 | $ | (23,998) |  |  | $ | (10,037) |
Income taxes | 1,437 |  |  | (383) |
Non-cash investing and financing activities: |  |  |
Net decrease in payables for purchases of property and equipment | $ | (5,420) |  |  | $ | (24,869) |
Net increase in deposits on equipment purchases | (4,196) |  |  | (13,552) |
Purchases of property and equipment through exchange of lease right of use asset | 334 |  |  | 26,133 |
Derecognition of right of use asset | (334) |  |  | (31,179) |

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
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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 and consolidating interest of a joint venture (collectively referred to herein as “we,” “us,” “our,” “ours” and like terms). All intercompany accounts and transactions have been eliminated. Patterson-UTI Energy, Inc. conducts its business operations through its wholly-owned subsidiaries and has no employees or independent operations. Certain immaterial prior year amounts have been reclassified to conform to current year presentation.
The U.S. dollar is the reporting currency and functional currency for most of our operations except certain of our foreign subsidiaries, which use their local currencies as their functional currency. Assets and liabilities of these foreign subsidiaries are translated into U.S. dollars using the exchange rates in effect as of the balance sheet date. The effects of these translation adjustments are reflected in accumulated other comprehensive income, which is a separate component of stockholders’ equity.
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 (“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 GAAP have been included. The unaudited condensed consolidated balance sheet as of December 31, 2024, as presented herein, was derived from our audited consolidated balance sheet but does not include all disclosures required by 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, 2024 (our “Annual Report”). The results of operations for the three months ended March 31, 2025 are not necessarily indicative of the results to be expected for the full year.
There have been no material changes to our critical accounting policies from those disclosed in our Annual Report.
Restricted cash — Restricted cash includes amounts restricted as cash collateral for the issuance of standby letters of credit.
The following table provides a reconciliation of cash and restricted cash reported within the unaudited condensed consolidated balance sheets that sum to the total of such amounts shown in the unaudited condensed statements of cash flows for the three months ended March 31, 2025 and 2024:

| Three Months Ended March 31,
| 2025 |  | 2024
Cash and cash equivalents | $ | 223,087 |  |  | $ | 167,665 |
Restricted cash | 2,117 |  |  | 2,582 |
Total cash, cash equivalents and restricted cash | $ | 225,204 |  |  | $ | 170,247 |

Recently Adopted Accounting Standards — In November 2023, the FASB issued an accounting standards update to improve reportable segment disclosure requirements and enhance disclosures about significant segment expenses. We adopted this new accounting pronouncement effective January 1, 2024 and expanded our consolidated financial statement disclosures in order to comply with the update. See Note 14 for details.
Recently Issued Accounting Standards — In December 2023, the FASB issued an accounting standards update to improve income tax disclosure requirements. We plan to adopt this accounting pronouncement during fiscal year 2025, with the first disclosure enhancements to be reflected in our Annual Report on Form 10-K for the year ending December 31, 2025. We are currently evaluating the impact this pronouncement will have on our disclosures.
In November 2024, the FASB issued guidance expanding disclosure requirements related to certain income statement expenses, which requires public entities to disclose additional information about specific expense categories in the notes to the financial statements on an interim and annual basis. This guidance is effective for annual reporting periods beginning after December 15, 2026 and interim periods beginning after December 15, 2027, with early adoption permitted. We are currently evaluating the effect of this pronouncement on our disclosures.
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2. Revenues
ASC Topic 606 Revenue from Contracts with Customers
Drilling Services and Completion Services — revenue is recognized based on our customers’ ability to benefit from our services in an amount that reflects the consideration we expect to receive in exchange for those services. This typically happens when the service is performed. The services we provide represent a series of distinct services, generally provided daily, that are substantially the same, with the same pattern of transfer to the customer. Because our customers benefit equally throughout the service period, generally measured in days, and our efforts in providing services are incurred relatively evenly over the period of performance, revenue is recognized as we provide services to the customer.
Drilling Services revenue primarily consists of daywork drilling contracts for which related revenues and expenses are recognized as services are performed. For certain contracts, we receive payments for the mobilization of rigs and other drilling equipment. We defer revenue and related direct operating expense related to mobilizations and recognize those revenues and expenses on a straight-line basis as drilling services are provided. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred and are recorded in Drilling Services operating expense in the Consolidated Statements of Operations and Comprehensive Income (Loss). For certain contracts, we are also entitled to early termination payments if our customers choose to terminate a contract prior to the expiration of the contractual term. We recognize revenue associated with early termination payments when all contractual requirements related to early termination payments have been met.
Completion Services revenue consists of services and products related to our suite of completion businesses, including hydraulic fracturing, completion support services, wireline and pumpdown services, and cementing. These services are provided pursuant to contractual arrangements, including pricing agreements. Revenue from these services is earned as services are rendered, which is generally on a per stage or fixed monthly rate, except for our cementing services. All revenue is recognized when a contract with a customer exists, the performance obligations under the contract have been satisfied over time, the amount to which we have the right to invoice has been determined and collectability of amounts subject to invoice is probable. Contract fulfillment costs, such as mobilization costs and shipping and handling costs, are expensed as incurred and are recorded in Completion Services operating expense in the Consolidated Statements of Operations and Comprehensive Income (Loss). To the extent fulfillment costs are considered separate performance obligations that are billable to the customer, the amounts billed are recorded as revenue in the Consolidated Statements of Operations and Comprehensive Income (Loss).
Once a stage has been completed or products and services have been provided, a field ticket is created that includes charges for the service performed and the chemicals, proppant, and compressed natural gas consumed during the course of the service. The field ticket may also include charges for the mobilization of the equipment and inventory to the location, any additional equipment used on the job, and other miscellaneous items. The field ticket represents the amounts to which we have the right to invoice and to recognize as revenue.
A portion of our contracts contain variable consideration; however, this variable consideration is typically unknown at the time of contract inception, and is not known until the job is complete, at which time the variability is resolved. Examples of variable consideration include the number of hours that will be incurred and the amount of consumables (such as chemicals and proppants) that will be used to complete a job.
Revenue is presented net of any sales tax charged to the customer that we are required to remit to local or state governmental taxing authorities. 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.
ASC Topic 842 Revenue from Equipment Rentals
Drilling Products Revenue — revenues are primarily generated from the rental of drilling equipment, comprised of drill bits and downhole tools. These arrangements provide the customer with the right to control the use of the identified asset. Generally, the lease terms in such arrangements are for periods of two to three days and do not provide customers with options to purchase the underlying asset.
Other — we are a non-operating working interest owner of oil and natural gas assets 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.
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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.
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 reactivation or initial mobilization of newly constructed or upgraded rigs that were moved on location to the initial well site. These payments are allocated to the overall performance obligation and amortized over the initial term of the contract. Total contract liability balances were $14.4 million and $75.6 million as of March 31, 2025 and December 31, 2024, respectively. We recognized $59.3 million of revenue during the three months ended March 31, 2025 that was included in the contract liability balance at the beginning of the period. Revenue related to our contract liabilities balance is expected to be recognized through 2028. The $14.0 million current portion of our contract liability balance is included in “Accrued liabilities” and the $0.4 million noncurrent portion of our contract liability balance is included in “Other liabilities” in our consolidated balance sheets.
Contract Costs
Costs incurred for newly constructed rigs or rig upgrades based on a contract with a customer are considered capital improvements and are capitalized to drilling equipment and depreciated over the estimated useful life of the asset.
Remaining Performance Obligations
We maintain a backlog of commitments for contract drilling services under term contracts, which we define as contracts with a duration of six months or more. Our contract drilling backlog in the United States as of March 31, 2025 was approximately $407 million. Approximately 9% of our total contract drilling backlog in the United States at March 31, 2025 is reasonably expected to remain at March 31, 2026. 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 commodity pricing or other related indices in effect at March 31, 2025. 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.
3. Inventory
Inventory consisted of the following at March 31, 2025 and December 31, 2024 (in thousands):

| March 31, 2025 |  | December 31, 2024
Raw materials and supplies | $ | 126,527 |  |  | $ | 121,694 |
Work-in-process | 6,747 |  |  | 6,681 |
Finished goods | 34,493 |  |  | 38,648 |
Inventory | $ | 167,767 |  |  | $ | 167,023 |

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4. Other Current Assets
Other current assets consisted of the following at March 31, 2025 and December 31, 2024 (in thousands):

| March 31, 2025 |  | December 31, 2024
Federal and state income taxes receivable | $ | 22,963 |  |  | $ | 24,777 |
Workers’ compensation receivable | 33,240 |  |  | 33,240 |
Prepaid expenses | 28,789 |  |  | 34,004 |
Other | 39,156 |  |  | 31,172 |
Other current assets | $ | 124,148 |  |  | $ | 123,193 |

5. Property and Equipment
Property and equipment consisted of the following at March 31, 2025 and December 31, 2024 (in thousands):

| March 31, 2025 |  | December 31, 2024
Equipment | $ | 8,252,210 |  |  | $ | 8,416,063 |
Oil and natural gas properties | 244,558 |  |  | 243,663 |
Buildings | 248,515 |  |  | 248,739 |
Rental equipment | 141,883 |  |  | 136,256 |
Land | 43,683 |  |  | 37,847 |
Total property and equipment | 8,930,849 |  |  | 9,082,568 |
Less accumulated depreciation, depletion, amortization and impairment | (5,993,786) |  |  | (6,072,226) |
Property and equipment, net | $ | 2,937,063 |  |  | $ | 3,010,342 |

Depreciation and depletion expense on property and equipment of approximately $199 million and $244 million was recorded in the three months ended March 31, 2025 and 2024, respectively.
We review our long-lived assets, including property and equipment and definite-lived intangible assets, 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 the undiscounted future cash flows over the life of the primary asset in an asset group. 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.
During 2024, negative market indicators such as lower industry-wide drilling rig and pressure pumping fleet count forecasts, increased volatility and pricing declines in the pressure pumping market, and continued efficiency gains and technology advancements reducing operating days led to our reduced outlook for activity. The reduction in activity forecasts, the decline in the market price of our common stock, and the results of the fair value determination of certain of our reporting units, were triggering events indicating that certain of our long-lived tangible and definite-lived intangible assets may have been impaired. We deemed it necessary to perform recoverability tests on our asset groups within our completion services reporting unit and our Latin American contract drilling asset group as of September 30, 2024. Future cash flows were estimated over the expected remaining life of the primary asset for each asset group, and we determined that, on an undiscounted basis, expected cash flows exceeded the carrying value of the asset groups. As such, no impairment was indicated for our long-lived tangible or definite-lived intangible assets.
During the first quarter of 2025, the majority of our primary market indicators stabilized as did management’s outlook on future activity. As such, we concluded there was no indication of a triggering event related to our long-lived tangible and definite-lived intangible asset groups as of March 31, 2025.
Subsequent to March 31, 2025, global economic conditions deteriorated, in part, because of recently enacted trade policies and tariffs implemented by the United States and other governments, as well as uncertainty regarding potential future changes to global trade policies and tariffs. Additionally, subsequent to March 31, 2025, several OPEC+ countries announced plans to phase out existing crude oil output cuts earlier than anticipated. These developments and geopolitical tensions have introduced increased uncertainty in global energy markets, which has contributed to a decline in our share price, lowered crude oil futures prices and
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increased uncertainty regarding the future economic environment in which we operate. The recent deterioration in macroeconomic conditions and the decline in our share price occurred after the balance sheet date and do not reflect conditions that existed as of March 31, 2025. Accordingly, these developments have not been reflected in the unaudited condensed consolidated financial statements for the three months ended March 31, 2025.
While the full effects are yet to be determined, prolonged trade tensions and sustained lower crude oil futures prices could adversely affect our future outlook on activity and profitability. If these conditions persist or deteriorate further, or if other unforeseen macroeconomic conditions emerge, they could negatively impact the expected cash flows used in our recoverability tests for our asset groups. Such changes could result in impairment charges in the future, which could be material to our results of operations and financial statements as a whole. We are unable to reasonably estimate the magnitude or timing of any such potential impacts.
We will continue to monitor these developments and evaluate the implications for the recoverability of our long-lived tangible and definite-lived intangible assets in future interim periods.
6. Goodwill and Intangible Assets
Goodwill — During the three months ended March 31, 2025, there were no additions or impairments to goodwill. As of March 31, 2025 and December 31, 2024, our goodwill balance was $487 million.
Goodwill is evaluated at least annually on July 31, or more frequently when events and circumstances occur indicating recorded goodwill may be impaired. Goodwill is tested at the reporting unit level, which is at or one level below 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. Any necessary goodwill impairment is determined using a quantitative impairment test. 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. The fair value of a reporting unit is determined using significant unobservable inputs, or level 3 in the fair value hierarchy. These inputs are based on internal management estimates, forecasts, and significant judgment.
We determined our drilling products operating segment consists of a single reporting unit and, accordingly, goodwill acquired from our acquisition of Ulterra Drilling Technologies, L.P. in 2023 was allocated to that reporting unit. We determined our completion services operating segment consisted of two reporting units; completion services, which was primarily comprised of our hydraulic fracturing operations and other integrated service offerings, and cementing services.
Goodwill Impairment Assessment
During 2024, negative market indicators such as lower industry-wide drilling rig and pressure pumping fleet count forecasts, increased volatility and pricing declines in the pressure pumping market, and continued efficiency gains and technology advancements reducing operating days led to our reduced outlook for activity. During the third quarter of 2024, we determined that the reduction in activity forecasts combined with the decline in the market price of our common stock was a triggering event that warranted a quantitative assessment for goodwill impairment.
In connection with this 2024 assessment, we estimated the fair value of the drilling products and the completion services reporting units using the income approach. Under this approach, we used a discounted cash flow model, which utilized present values of cash flows to estimate fair value. Forecasted cash flows reflected known market conditions in the third quarter of 2024 and management's anticipated business outlook for each reporting unit. Future cash flows were projected based on estimates of revenue growth rates, gross profit, selling, general and administrative expense, changes in working capital, and capital expenditures. The terminal period used within the discounted cash flow model for each reporting unit consisted of a 1% growth estimate. Future cash flows were then discounted using a market-participant, risk-adjusted weighted average cost of capital of 10.25% for the drilling products reporting unit and 10.75% for the completion services reporting unit. Financial and credit market volatility directly impacts our fair value measurement through the weighted average cost of capital used to determine a discount rate. During times of volatility, significant judgment must be applied to determine whether credit market changes are a short-term or long-term trend.
In connection with this 2024 assessment, we estimated the fair value of the cementing services reporting unit in our completion services operating segment using a market approach. The market approach was based on trading multiples of earnings before interest, taxes, depreciation and amortization for companies comparable to the cementing services reporting unit.
For purposes of our 2024 assessment, the forecast for the completion services reporting unit assumed lower activity in 2025 compared to average activity levels for full year 2024 and increases in estimated activity of 2% to 8% beginning in 2026 through 2029. Those estimates were based on future drilling rig and pressure pumping fleet count forecasts during the third quarter of 2024 and estimated market share. Additionally, the forecast reflected the expectation that industry-wide pricing pressure would persist
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within the completions market and continue to compress adjusted gross profit. These factors negatively impacted the estimated value of the reporting unit.
Based on the results of the quantitative assessment, the fair value of the completion services reporting unit was less than its carrying value. Accordingly, we recorded an $885 million impairment charge to goodwill for the completion services reporting unit during the third quarter of 2024.
The forecast for the drilling products reporting unit assumed continued growth domestically as well as in international markets. Geopolitical instability in regions in which we expect to maintain and grow market share, a global decrease in the demand of drilling products, or other unforeseen macroeconomic considerations could negatively impact the key assumptions used in our goodwill assessment for our drilling products reporting unit.
During the first quarter of 2025, the majority of our primary market indicators stabilized as did management’s outlook on future activity. As such, as of March 31, 2025, we determined there were no events that would indicate the carrying value of goodwill may not be recoverable or that potential impairment exists.
Subsequent to March 31, 2025, global economic conditions deteriorated, in part, because of recently enacted trade policies and tariffs implemented by the United States and other governments, as well as uncertainty regarding potential future changes to global trade policies and tariffs. Additionally, subsequent to March 31, 2025, several OPEC+ countries announced plans to phase out existing crude oil output cuts earlier than anticipated. These developments and geopolitical tensions have introduced increased uncertainty in global energy markets, which has contributed to a decline in our share price, lowered crude oil futures prices and increased uncertainty regarding the future economic environment in which we operate. The recent deterioration in macroeconomic conditions and the decline in our share price occurred after the balance sheet date and do not reflect conditions that existed as of March 31, 2025. Accordingly, these developments have not been reflected in the unaudited condensed consolidated financial statements for the three months ended March 31, 2025.
While the full effects are yet to be determined, prolonged trade tensions and sustained lower crude oil futures prices could adversely affect our future outlook on activity and profitability. If these conditions persist or deteriorate further, or if other unforeseen macroeconomic conditions emerge, they could negatively impact the key assumptions used in our goodwill assessment for our drilling products and cementing services reporting units. A decrease in fair value resulting from unfavorable changes to these assumptions, or others, could result in goodwill impairment in future periods that could be material to our results of operations and financial statements as a whole. We are unable to reasonably estimate the magnitude or timing of any such potential impacts.
We will continue to monitor these developments and evaluate the implications on the carrying value of goodwill in future interim periods.
Intangible Assets — The following table presents the gross carrying amount and accumulated amortization of our intangible assets as of March 31, 2025 and December 31, 2024 (in thousands):

| March 31, 2025 |  | December 31, 2024
| Gross Carrying Amount |  | Accumulated Amortization |  | Net Carrying Amount |  | Gross Carrying Amount |  | Accumulated Amortization |  | Net Carrying Amount
Customer relationships | $ | 782,968 |  |  | $ | (113,384) |  |  | $ | 669,584 |  |  | $ | 782,789 |  |  | $ | (95,785) |  |  | $ | 687,004 |
Developed technology | 202,771 |  |  | (66,867) |  |  | 135,904 |  |  | 202,772 |  |  | (56,562) |  |  | 146,210 |
Trade name | 101,000 |  |  | (15,906) |  |  | 85,094 |  |  | 101,000 |  |  | (14,097) |  |  | 86,903 |
Other | 14,812 |  |  | (4,435) |  |  | 10,377 |  |  | 12,986 |  |  | (3,493) |  |  | 9,493 |
Intangible assets, net | $ | 1,101,551 |  |  | $ | (200,592) |  |  | $ | 900,959 |  |  | $ | 1,099,547 |  |  | $ | (169,937) |  |  | $ | 929,610 |

Amortization expense on intangible assets of approximately $30.8 million and $30.5 million was recorded for the three months ended March 31, 2025 and 2024, respectively.
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7. Accrued Liabilities
Accrued liabilities consisted of the following at March 31, 2025 and December 31, 2024 (in thousands):

| March 31, 2025 |  | December 31, 2024
Salaries, wages, payroll taxes and benefits | $ | 79,013 |  |  | $ | 110,212 |
Workers’ compensation liability | 72,299 |  |  | 73,730 |
Property, sales, use and other taxes | 45,593 |  |  | 54,445 |
Insurance, other than workers’ compensation | 10,738 |  |  | 10,703 |
Accrued interest payable | 10,001 |  |  | 17,484 |
Deferred revenue | 14,034 |  |  | 75,195 |
Accrued merger and integration expense | 3,018 |  |  | 4,723 |
Other | 38,982 |  |  | 39,259 |
Accrued liabilities | $ | 273,678 |  |  | $ | 385,751 |

8. Long-Term Debt
Long-term debt consisted of the following at March 31, 2025 and December 31, 2024 (in thousands):

| March 31, 2025 |  | December 31, 2024
3.95% Senior Notes Due 2028 | $ | 482,505 |  |  | $ | 482,505 |
5.15% Senior Notes Due 2029 | 344,895 |  |  | 344,895 |
7.15% Senior Notes Due 2033 | 400,000 |  |  | 400,000 |
Equipment Loans Due 2025 | 3,219 |  |  | 6,395 |
| 1,230,619 |  |  | 1,233,795 |
Less deferred financing costs and discounts | (7,319) |  |  | (7,637) |
Less current portion | (3,217) |  |  | (6,388) |
Total | $ | 1,220,083 |  |  | $ | 1,219,770 |

Credit Agreement — On January 31, 2025, we entered into the Second Amended and Restated Credit Agreement with the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent, and the other parties thereto (the “Credit Agreement”). The Credit Agreement amended and restated our Amended and Restated Credit Agreement dated as of March 27, 2018 (as amended, restated, supplemented or otherwise modified at December 31, 2024, the “Prior Credit Agreement”). The commitments under the Credit Agreement are $500 million, and the loans and commitments under the Credit Agreement mature on January 31, 2030.
The Credit Agreement provides for a committed senior unsecured credit facility that permits aggregate revolving credit borrowings of up to $500 million, with a letter of credit sub-facility of $100 million and a swing line sub-facility that, at any time outstanding, is limited to the lesser of $50 million and the amount of the swing line provider’s unused commitment. Subject to customary conditions, we may request that the lenders’ aggregate commitments be increased by up to $200 million, not to exceed total commitments of $700 million.
Loans under the Credit Agreement bear interest by reference, at our election, to the SOFR rate (plus a 0.10% per annum adjustment) or base rate, in each case subject to a 0% floor. The applicable margin on SOFR rate loans varies from 1.25% to 2.25% and the applicable margin on base rate loans varies from 0.25% to 1.25%, in each case determined based on our credit rating. As of March 31, 2025, the applicable margin on SOFR 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 SOFR 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 0.15% to 0.35% 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, which does not qualify for certain limited exceptions and is otherwise, in the aggregate with all other similar debt, in excess of Priority Debt (as defined in the Credit Agreement), such subsidiary is required to become a guarantor under the Credit Agreement.
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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 grant liens and on the ability of each of our non-guarantor subsidiaries to incur debt. 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 generally 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 both credit rating agencies. The Credit Agreement also requires that our total debt to capitalization ratio, expressed as a percentage, not exceed 50% as of the last day of each fiscal quarter. 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 March 31, 2025.
As of March 31, 2025, we had no borrowings outstanding under our Credit Agreement. We had $2.0 million in letters of credit outstanding under the Credit Agreement at March 31, 2025 and, as a result, had available borrowing capacity of approximately $498 million under the Credit Agreement at that date.
2015 Reimbursement Agreement — On March 16, 2015, we entered into a Reimbursement Agreement (as amended from time to time, 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 March 31, 2025, we had $38.8 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 of our letters of credit issued thereunder. 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 Prime rate plus 2.00% 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. A letter of credit fee is payable by us equal to 1.50% times the amount of outstanding letters of credit.
We have also agreed that if obligations under the Credit Agreement are secured by liens on any of our or our subsidiaries’ property, then our reimbursement obligations and (to the extent similar obligations would be secured under the Credit Agreement) other obligations under the Reimbursement Agreement and any letters of credit will be equally and ratably secured by all property subject to such liens securing the Credit Agreement.
Pursuant to a Continuing Guaranty dated as of March 16, 2015, our payment obligations under the Reimbursement Agreement are jointly and severally guaranteed as to payment and not as to collection by our subsidiaries that from time to time guarantee payment under the Credit Agreement. None of our subsidiaries are currently required to guarantee payment under the Credit Agreement.
2028 Senior Notes, 2029 Senior Notes and 2033 Senior Notes — On January 19, 2018, we completed an offering of $525 million in aggregate principal amount of 3.95% Senior Notes due 2028 (the “2028 Notes”). On November 15, 2019, we completed an offering of $350 million in aggregate principal amount of 5.15% Senior Notes due 2029 (the “2029 Notes”). On September 13, 2023, we completed an offering of $400 million in aggregate principal amount of 7.15% Senior Notes due 2033 (the “2033 Notes”). The net proceeds before offering expenses from the offering of the 2033 Notes were approximately $396 million, which we used to repay amounts outstanding under the Prior Credit Agreement.
We pay interest on the 2028 Notes on February 1 and August 1 of each year. The 2028 Notes will mature on February 1, 2028. The 2028 Notes bear interest at a rate of 3.95% per annum.
We pay interest on the 2029 Notes on May 15 and November 15 of each year. The 2029 Notes will mature on November 15, 2029. The 2029 Notes bear interest at a rate of 5.15% per annum.
We pay interest on the 2033 Notes on April 1 and October 1 of each year. The 2033 Notes will mature on October 1, 2033. The 2033 Notes bear interest at a rate of 7.15% per annum.
The 2028 Notes, 2029 Notes and 2033 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
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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, on August 15, 2029, in the case of the 2029 Notes, and on July 1, 2033, in the case of the 2033 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 applicable 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 applicable 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.
Presented below is a schedule of the principal repayment requirements of long-term debt by fiscal year as of March 31, 2025 (in thousands):

Year ending December 31, |
2025 | $ | 3,219 |
2026 | — |
2027 | — |
2028 | 482,505 |
2029 | 344,895 |
Thereafter | 400,000 |
Total | $ | 1,230,619 |

9. Commitments and Contingencies
As of March 31, 2025, we maintained letters of credit in the aggregate amount of $42.8 million primarily for the benefit of various insurance companies as collateral for retrospective premiums and retained losses that could become payable under the terms of the underlying insurance contracts and compliance with contractual obligations. These letters of credit expire annually at various times during the year and are typically renewed. As of March 31, 2025, no amounts had been drawn under the letters of credit. As of March 31, 2025, we had $35.0 million in surety bond exposure issued as financial assurance on an insurance agreement.
As of March 31, 2025, we had commitments to purchase major equipment totaling approximately $111 million.
Our completion services segment has entered into agreements to purchase minimum quantities of proppants from certain vendors. As of March 31, 2025, the remaining minimum obligation under these agreements was approximately $18.7 million, of which approximately $13.6 million and $5.1 million relate to the remainder of 2025 and 2026, respectively.
Certain subsidiaries we acquired in the Ulterra acquisition are defendants in a claim brought by a subsidiary of NOV Inc. alleging breach of a license agreement related to certain patents. Such subsidiaries have asserted defenses to the claim and are defending vigorously against this claim.
On February 6, 2023, Grant Prideco, Inc., ReedHycalog UK, Ltd. ReedHycalog, LP, National Oilwell Varco, LP (“NOV”) sued Ulterra Drilling Technologies, LP (“Ulterra”) and several other companies in Texas state court. NOV seeks a declaration that
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United States Patent No. 8,721,752 (the “’752 Patent”) is a “Licensed RH Patent” per the terms of a license agreement between Ulterra and NOV. NOV also alleges a breach of contract based on the license agreement between NOV and Ulterra and seeks allegedly owed royalties since October 22, 2021. NOV also seeks attorney’s fees.
On February 27, 2023, Ulterra filed a plea to the jurisdiction, and subject thereto, an answer, affirmative defenses and counterclaims. Ulterra’s counterclaims include: (i) declaratory judgments of non-infringement of U.S. Pat. No. 7,568,534 and the ’752 patent; (ii) a declaratory judgment of no royalties after Oct. 22, 2021; (iii) a declaratory judgment that certain other identified patents are expired and therefore not infringed after Oct. 22, 2021; and (iv) a declaratory judgment of no breach of contract. On the same day, Ulterra filed a notice of removal in federal court for the Southern District of Texas, Houston Division (SDTX 4:23-cv-00730), as well as a corresponding notice in Texas state court. NOV moved to dismiss and remand the case back to state court. On February 17, 2024, the Court denied NOV’s motion. On March 19, 2024, Ulterra moved for judgment on the pleadings regarding its declaratory judgment that certain other identified patents are expired and therefore not infringed after October 22, 2021. On February 13, 2025, the motion was granted in part and denied in part.
Discovery is closed and dispositive motions are fully briefed. Trial is currently scheduled for October 27, 2025. An unfavorable judgment or resolution of this claim not covered by indemnity could have a material impact on our financial results.
Additionally, we are party to various other 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
Cash Dividend — On April 23, 2025, our Board of Directors approved a cash dividend on our common stock in the amount of $0.08 per share to be paid on June 16, 2025 to holders of record as of June 2, 2025. The amount and timing of all future dividend payments, if any, are subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of our debt agreements and other factors. Our Board of Directors may, without advance notice, reduce or suspend our dividend for any reason, including to improve our financial flexibility and position our company for long-term success. There can be no assurance that we will pay a dividend in the future.
Share Repurchases and Acquisitions — In September 2013, our Board of Directors approved a stock buyback program. In February 2024, our Board of Directors approved an increase of the authorization under the stock buyback program to allow for an aggregate of $1.0 billion of future share repurchases. All purchases executed to date have been through open market transactions. Purchases under the buyback 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 March 31, 2025, we had remaining authorization to purchase approximately $741 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 three months ended March 31, 2025 were as follows (dollars in thousands):

| Shares |  | Cost
Treasury shares at January 1, 2025 | 133,440,028 |  | $ | 1,951,067 |
Purchases pursuant to stock buyback program | 2,078,723 |  |  | 18,062 |
Acquisitions pursuant to long-term incentive plans | 258,558 |  |  | 2,233 |
Treasury shares at March 31, 2025 | 135,777,309 |  | $ | 1,971,362 |

11. Stock-based Compensation
We use share-based payments to compensate employees and non-employee directors. We recognize the cost of share-based payments under the fair-value-based method. Share-based awards include equity instruments in the form of stock options 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. We issue shares of common stock when vested stock options are exercised and after restricted stock units and share-settled performance unit awards vest.
Stock Options — We estimate the grant date fair values of stock options using the Black-Scholes-Merton valuation model. Volatility assumptions are based on the historic volatility of our common stock over the most recent period equal to the expected term of the options as of the date such options are granted. The expected term assumptions are based on our experience with respect
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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 three months ended March 31, 2025 or 2024.
Stock option activity from January 1, 2025 to March 31, 2025 follows:

| Underlying Shares |  | Weighted Average Exercise Price Per Share
Outstanding at January 1, 2025 | 1,794,005 |  | $ | 22.26 |
Exercised | — |  | $ | — |
Expired | — |  | $ | — |
Outstanding at March 31, 2025 | 1,794,005 |  | $ | 22.26 |
Exercisable at March 31, 2025 | 1,794,005 |  | $ | 22.26 |

Restricted Stock Units (Equity Based) — For all restricted stock unit awards made to date, shares of common stock are not issued until the units vest. Restricted stock units are subject to forfeiture for failure to fulfill service conditions and, in certain cases, performance conditions. Forfeitable dividend equivalents are accrued on certain restricted stock units that will be paid upon vesting. We use the straight-line method to recognize periodic compensation cost over the vesting period.
Restricted stock unit activity from January 1, 2025 to March 31, 2025 follows:

| Time Based |  | Performance Based |  | Weighted Average Grant Date Fair Value Per Share
Non-vested restricted stock units outstanding at January 1, 2025 | 5,427,657 |  | 452,514 |  | $ | 11.34 |
Granted | 220,335 |  | — |  | $ | 8.26 |
Vested | (970,539) |  | — |  | $ | 9.79 |
Forfeited | (33,991) |  | — |  | $ | 10.77 |
Non-vested restricted stock units outstanding at March 31, 2025 | 4,643,462 |  | 452,514 |  | $ | 11.51 |

As of March 31, 2025, we had unrecognized compensation cost related to our unvested restricted stock units totaling $35.1 million. The weighted-average remaining vesting period for these unvested restricted stock units was 1.63 years as of March 31, 2025.
Restricted Stock Units (Liability Based) — We converted cash-settled performance based units that had been granted by NexTier Oilfield Solutions Inc. (“NexTier”) into our cash-settled restricted stock units in connection with our merger with NexTier. These awards were accounted for as liability classified awards and remeasured at fair value at each reporting period. Compensation expense was recorded over the vesting period and was initially based on the fair value at the award conversion date. Compensation expense was subsequently remeasured at each reporting date during the vesting period based on the change in our stock price. Dividend cash equivalents are not paid on cash-settled units. We settled the NexTier cash-settled performance based units in January 2025, with a cash payment of $3.3 million.
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 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 generally the three-year period commencing on April 1 of the year of grant, except as described below for the Performance Units granted in May 2024.
The performance goals for the Performance Units are tied to our total shareholder return for the performance period as compared to total shareholder return for a peer group determined by the Compensation Committee. For the performance units granted in April 2022, the peer group includes one market index. The performance goals are considered to be market conditions under the relevant accounting standards and the market conditions were factored into the determination of the fair value of the respective Performance Units. For the Performance Units granted in April 2022 and May 2023, 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
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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.
The Performance Units granted in May 2024 (the “2024 Performance Units”) are subject to three separate performance periods—a one-year performance period (the “First Performance Period”), a two-year performance period (the “Second Performance Period”) and a three-year performance period (the “Third Performance Period”), each commencing on April 1, 2024. One-third of the total target number of shares subject to the 2024 Performance Units may become earned in respect of each performance period based on our total shareholder return during such performance period (the target number of shares eligible to vest in the applicable performance period, the “Performance Period Target Amount”). The recipients will earn the Performance Period Target Amount if our total shareholder return during the applicable performance period, when compared to the peer group, is at the 55th percentile. If our total shareholder return during the applicable performance period, when compared to the peer group, is at the 75th percentile or higher, then the recipients will earn two times the Performance Period Target Amount. If our total shareholder return during the applicable performance period, when compared to the peer group, is at the 25th percentile, then the recipients will only earn one-half of the Performance Period Target Amount. If our total shareholder return during the applicable performance period, when compared to the peer group, is between the 25th and 55th percentile, or the 55th and 75th percentile, then the shares to be earned by the recipients will be determined using linear interpolation for levels of achievement between these points. Notwithstanding the foregoing, a number of shares no greater than the Performance Period Target Amount may be earned for each of the First Performance Period and the Second Performance Period, unless our total shareholder return during the Third Performance Period is greater than our total shareholder return for, as applicable, the First Performance Period and/or the Second Performance Period, in which case, the number of shares earned in respect of the First Performance and/or the Second Performance Period, as applicable, will be determined as if our total shareholder return during the Third Performance Period was our total shareholder return during the First Performance Period and/or the Second Performance Period, as applicable. If our total shareholder return during the Third Performance Period is zero or negative, no more than the aggregate target number of shares subject to the 2024 Performance Units may be earned, regardless of results during the First Performance Period and the Second Performance Period. A full three-year service vesting period applies to the Performance Units and no shares will vest and be delivered in respect of the 2024 Performance Units until after the completion of the Third Performance Period.
The payout under the 2024 Performance Units may not exceed the target number of shares if our absolute total shareholder return is negative or zero.
The total target number of shares granted with respect to the Performance Units for the awards granted in 2021-2024 is set forth below:

| 2024 Performance Unit Awards |  | 2023 Performance Unit Awards |  | 2022 Performance Unit Awards |  | 2021 Performance Unit Awards
Target number of shares | 875,100 |  | 631,700 |  | 414,000 |  | 843,000

In May 2024, 718,581 shares were issued to settle the 2021 Performance Units. The Performance Units granted in 2022 have reached the end of their performance period, and we expect no shares will be issued to settle the 2022 Performance Units. The Performance Units granted in 2023 and 2024 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):

| 2024 Performance Unit Awards |  | 2023 Performance Unit Awards |  | 2022 Performance Unit Awards |  | 2021 Performance Unit Awards
Aggregate fair value at date of grant | $ | 10,904 |  |  | $ | 8,440 |  |  | $ | 10,743 |  |  | $ | 7,225 |

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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 set forth below (in thousands):

| 2024 Performance Unit Awards |  | 2023 Performance Unit Awards |  | 2022 Performance Unit Awards |  | 2021 Performance Unit Awards
Three months ended March 31, 2025 | $ | 899 |  |  | $ | 654 |  |  | $ | 850 |  |  | NA
Three months ended March 31, 2024 | NA |  | $ | 663 |  |  | $ | 862 |  |  | $ | 584 |

As of March 31, 2025, we had unrecognized compensation cost related to our unvested Performance Units totaling $10.4 million. The weighted-average remaining vesting period for these unvested Performance Units was 1.25 years as of March 31, 2025.
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 GAAP and tax accounting.
Our effective income tax rate for the three months ended March 31, 2025 was 51.9%, compared with 27.9% for the three months ended March 31, 2024. The difference in effective income tax rates between the periods was primarily attributable to the impact of permanent differences against earnings between periods.
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.
We continue to monitor income tax developments in the United States and other countries where we have legal entities. We will incorporate into our future financial statements the impacts, if any, of future regulations and additional authoritative guidance when finalized.
13. Earnings Per Share
We provide a dual presentation of our net income (loss) per common share in our unaudited condensed consolidated statements of operations: basic net income (loss) per common share (“Basic EPS”) and diluted net income (loss) per common share (“Diluted EPS”).
Basic EPS excludes dilution and is determined by dividing the earnings attributable to common stockholders by the weighted average number of common shares outstanding during the period.
Diluted EPS is based on the weighted average number of common shares outstanding plus the dilutive effect of potential common shares, including stock options and non-vested performance units and non-vested restricted stock units. The dilutive effect of stock options, non-vested performance units and non-vested restricted stock units is determined using the treasury stock method.
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The following table presents information necessary to calculate net income (loss) per share for the three months ended March 31, 2025 and 2024 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 March 31, |  |
| 2025 |  | 2024 |  |  |  |
BASIC EPS: |  |  |  |  |  |  |
Net income attributable to common stockholders | $ | 1,005 |  |  | $ | 51,235 |  |  |  |  |
Weighted average number of common shares outstanding, excluding non-vested restricted stock units | 386,521 |  | 408,182 |  |  |  |
Basic net income per common share | $ | 0.00 |  |  | $ | 0.13 |  |  |  |  |
DILUTED EPS: |  |  |  |  |  |  |
Net income attributable to common stockholders | $ | 1,005 |  |  | $ | 51,235 |  |  |  |  |
Weighted average number of common shares outstanding, including non-vested restricted stock units | 387,044 |  | 409,819 |  |  |  |  |
Diluted net income per common share | $ | 0.00 |  |  | $ | 0.13 |  |  |  |  |
Potentially dilutive securities excluded as anti-dilutive | 2,488 |  | 2,673 |  |  |  |

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14. Business Segments
Our Chief Operating Decision Maker (“CODM”) is our Chief Executive Officer, who has ultimate responsibility for enterprise decisions. Our business is organized based on the services and products we provide in three segments: (i) drilling services, (ii) completion services, and (iii) drilling products. The CODM evaluates segment performance based primarily on segment operating income (loss).
Drilling Services — represents our contract drilling, directional drilling, oilfield technology and electrical controls and automation businesses.
Completion Services — represents the combination of our well completion business, which includes hydraulic fracturing, wireline and pumping, completion support, cementing and our legacy pressure pumping business.
Drilling Products — represents our manufacturing and distribution of drill bits business.
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The following tables summarize selected financial information relating to our business segments (in thousands):

| Drilling Services |  | Completion Services |  | Drilling Products |  | Total
For the three months ended March 31, 2025 |  |  |  |  |  |  |
Revenues from external customers | $ | 412,860 |  |  | $ | 766,080 |  |  | $ | 85,663 |  |  | $ | 1,264,603 |
Direct operating costs (1) | 247,629 |  |  | 657,681 |  |  | 46,940 |  |  | 952,250 |
Selling, general and administrative | 3,945 |  |  | 11,409 |  |  | 9,119 |  |  | 24,473 |
Depreciation, amortization and impairment (1) | 84,972 |  |  | 115,826 |  |  | 22,876 |  |  | 223,674 |
Segment operating income (loss) (3) | $ | 76,314 |  |  | $ | (18,836) |  |  | $ | 6,728 |  |  | $ | 64,206 |
Reconciliation of revenue:
Total segment revenues from external customers |  |  |  |  |  |  | $ | 1,264,603 |
Other revenues (4) |  |  |  |  |  |  | 15,934 |
Total consolidated revenues |  |  |  |  |  |  | $ | 1,280,537 |
Reconciliation to consolidated income (loss) before income taxes:
Segment operating income (3) |  |  |  |  |  |  | $ | 64,206 |
Other (4) |  |  |  |  |  |  | 230 |
Corporate |  |  |  |  |  |  | (47,491) |
Interest income |  |  |  |  |  |  | 1,464 |
Interest expense |  |  |  |  |  |  | (17,697) |
Other income |  |  |  |  |  |  | 1,968 |
Income before income taxes |  |  |  |  |  |  | $ | 2,680 |
| Drilling Services |  | Completion Services |  | Drilling Products |  | Total
For the three months ended March 31, 2024 |  |  |  |  |  |  |
Revenues from external customers | $ | 457,573 |  |  | $ | 944,997 |  |  | $ | 89,973 |  |  | $ | 1,492,543 |
Direct operating costs (1) | 271,737 |  |  | 745,594 |  |  | 48,630 |  |  | 1,065,961 |
Selling, general and administrative | 3,879 |  |  | 10,964 |  |  | 7,661 |  |  | 22,504 |
Depreciation, amortization and impairment (1) | 92,345 |  |  | 148,680 |  |  | 27,182 |  |  | 268,207 |
Other segment items (2) | — |  |  | (9,870) |  |  | — |  |  | (9,870) |
Segment operating income (3) | $ | 89,612 |  |  | $ | 49,629 |  |  | $ | 6,500 |  |  | $ | 145,741 |
Reconciliation of revenue:
Total segment revenues from external customers |  |  |  |  |  |  | $ | 1,492,543 |
Other revenues (4) |  |  |  |  |  |  | 17,817 |
Total consolidated revenues |  |  |  |  |  |  | $ | 1,510,360 |
Reconciliation to consolidated income (loss) before income taxes:
Segment operating income (3) |  |  |  |  |  |  | $ | 145,741 |
Other (4) |  |  |  |  |  |  | 988 |
Corporate |  |  |  |  |  |  | (59,730) |
Interest income |  |  |  |  |  |  | 2,189 |
Interest expense |  |  |  |  |  |  | (18,335) |
Other income |  |  |  |  |  |  | 850 |
Income before income taxes |  |  |  |  |  |  | $ | 71,703 |

(1)The significant expense categories and amounts align with the segment-level information that is regularly provided to the chief operating decision maker.
(2)Other segment items for each reportable segment includes other operating expenses (income).
(3)Segment operating income (loss) is our measure of segment profitability. It is defined as revenue less operating expenses, selling, general and administrative expenses, depreciation, amortization and impairment expense and other operating expenses (income).
(4)Other includes our oilfield rentals business and oil and natural gas working interests.
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Other business segment information

| Three Months Ended March 31, |  |
| 2025 |  | 2024 |  |  |  |
Capital expenditures: |  |  |  |  |  |  |
Drilling Services | $ | 73,458 |  |  | $ | 82,793 |  |  |  |  |
Completion Services | 62,173 |  |  | 123,377 |  |  |  |  |
Drilling Products | 18,222 |  |  | 15,586 |  |  |  |  |
Segment capital expenditures | $ | 153,853 |  |  | $ | 221,756 |  |  |  |  |
Other | 3,596 |  |  | 3,797 |  |  |  |  |
Corporate | 4,382 |  |  | 1,388 |  |  |  |  |
Total capital expenditures | $ | 161,831 |  |  | $ | 226,941 |  |  |  |  |

| March 31, 2025 |  | December 31, 2024
Identifiable assets: |  |  |
Drilling Services | $ | 2,001,356 |  |  | $ | 2,047,986 |
Completion Services | 2,465,801 |  |  | 2,468,707 |
Drilling Products | 930,294 |  |  | 966,200 |
Segment assets | $ | 5,397,451 |  |  | $ | 5,482,893 |
Other | 50,647 |  |  | 55,580 |
Corporate (1) | 317,328 |  |  | 294,993 |
Total assets | $ | 5,765,426 |  |  | $ | 5,833,466 |

(1)Corporate assets primarily include cash on hand and certain property and equipment.
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15. Fair Values of Financial Instruments
The carrying values of cash, cash equivalents and restricted cash, 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 March 31, 2025 and December 31, 2024 is set forth below (in thousands):

| March 31, 2025 |  | December 31, 2024
| Carrying Value |  | Fair Value |  | Carrying Value |  | Fair Value
3.95% Senior Notes Due 2028 | $ | 482,505 |  |  | $ | 469,312 |  |  | $ | 482,505 |  |  | $ | 461,720 |
5.15% Senior Notes Due 2029 | 344,895 |  |  | 342,152 |  |  | 344,895 |  |  | 336,490 |
7.15% Senior Notes Due 2033 | 400,000 |  |  | 422,195 |  |  | 400,000 |  |  | 419,265 |
Equipment Loans Due 2025 | 3,219 |  |  | 3,234 |  |  | 6,395 |  |  | 6,424 |
Total debt | $ | 1,230,619 |  |  | $ | 1,236,893 |  |  | $ | 1,233,795 |  |  | $ | 1,223,899 |

The fair values of the 2028 Notes, the 2029 Notes and the 2033 Notes at March 31, 2025 and December 31, 2024 are based on quoted market prices, which are considered Level 1 fair value estimates in the fair value hierarchy of fair value accounting. The fair value of the secured equipment financing term loans (“Equipment Loans”) is based on a 5.25% stated rate of interest, which is considered a Level 2 fair value estimate in the fair value hierarchy of fair value accounting.
The implied market rates of interest used to determine the fair value of our outstanding debt balances as of March 31, 2025 and December 31, 2024 are set forth below:

| March 31, 2025 |  | December 31, 2024
3.95% Senior Notes Due 2028 | 5.00 | % |  | 5.49 | %
5.15% Senior Notes Due 2029 | 5.35 | % |  | 5.73 | %
7.15% Senior Notes Due 2033 | 6.30 | % |  | 6.42 | %
Equipment Loans Due 2025 | 4.95 | % |  | 5.28 | %

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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 economic downturns; 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,” “potential,” “predict,” “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 also include those set forth in Management’s Discussion and Analysis of Financial Condition and Results of Operations included in this Report and other sections of our filings with the United States Securities and Exchange Commission (the “SEC”) under the Exchange Act and the Securities Act, as well as, among others, risks and uncertainties relating to:
•adverse oil and natural gas industry conditions, including the impact of commodity price volatility on industry outlook;
•global economic conditions, including inflationary pressures and risks of economic downturns or recessions in the United States and elsewhere;
•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 supply of drilling and completions equipment, including as a result of reactivation, improvement or construction;
•competition and demand for our services;
•the impact of the ongoing Ukraine/Russia and Middle East conflicts and instability in other international regions;
•strength and financial resources of competitors;
•utilization, margins and planned capital expenditures;
•ability to obtain insurance coverage on commercially reasonable terms and 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 and the risk of obsolescence of existing technologies;
•the ability to attract and retain management and field personnel;
•loss of key customers;
•shortages, delays in delivery, and interruptions in supply, of equipment and materials;
•cybersecurity events;
•difficulty in building and deploying new equipment;
•complications with the design or implementation of our new enterprise resource planning system;
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•governmental regulation, including 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;
•changes to tax, tariff and import/export regulations and sanctions by the United States or other countries, including the impacts of any sustained escalation or changes in tariff levels or trade-related disputes;
•the ability to effectively identify and enter new markets or pursue strategic acquisitions;
•public health crises, pandemics and epidemics;
•weather;
•operating costs;
•expansion and development trends of the oil and natural gas industry;
•financial flexibility, including availability of capital and the ability to repay indebtedness when due;
•adverse credit and equity market conditions;
•our return of capital to stockholders, including timing and amounts (including any plans or commitments in respect thereof) of any dividends and share repurchases;
•stock price volatility;
•compliance with covenants under our debt agreements; and
•other financial, operational and legal risks and uncertainties detailed from time to time in our filings with the SEC.
We caution that the foregoing list of factors is not exhaustive. Additional information concerning these and other risk factors is contained elsewhere in this Report and in our Annual Report on Form 10-K for the year ended December 31, 2024 (our “Annual Report”) and may be contained in our future filings with the SEC. You are cautioned not to place undue reliance on any of our forward-looking statements. The forward-looking statements speak only as of the date made and, other than as required by law, we undertake no obligation to update publicly or revise any of these forward-looking statements, whether as a result of new information, future events or otherwise. In the event that we update any forward-looking statement, no inference should be made that we will make additional updates with respect to that statement, related matters or any other forward-looking statements. All subsequent written and oral forward-looking statements concerning us or other matters and attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements above.
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ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Management Overview — We are a Houston, Texas-based leading provider of drilling and completion services to oil and natural gas exploration and production companies in the United States and other select countries, including contract drilling services, integrated well completion services and directional drilling services in the United States, and specialized drill bit solutions in the United States, Middle East and many other regions around the world. We operate under three reportable business segments: (i) drilling services, (ii) completion services, and (iii) drilling products.
Drilling Services
Our contract drilling business operates in the continental United States and internationally in Colombia and Ecuador and, from time to time, we pursue contract drilling opportunities in other select markets. We also provide a comprehensive suite of directional drilling services in most major producing onshore oil and natural gas basins in the United States, and we provide services that improve the statistical accuracy of wellbore placement for directional and horizontal wells. We also service and re-certify 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.
As of March 31, 2025, we had 152 marketed land-based drilling rigs based in the following regions:

Region |  | Number of Rigs
West Texas |  | 71
Appalachia |  | 21
Oklahoma |  | 16
Rockies |  | 16
South Texas |  | 11
East Texas |  | 9
Colombia |  | 7
Ecuador |  | 1
Total |  | 152

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. The U.S. land rig industry has in recent years referred to certain high specification rigs as “super-spec” rigs, which we consider to be at least 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. Due to evolving customer preferences, we refer to certain premium rigs as “Tier-1, super spec” rigs, which we consider as being a super-spec rig that also has a third mud pump and raised drawworks that allows for more clearance underneath the rig floor. As of March 31, 2025, our rig fleet included 135 Tier-1, super-spec rigs.
Completion Services
Our well completion services business consists of services for hydraulic fracturing, wireline and pumping, completion support, and cementing. It also includes our power solutions natural gas fueling business and our proppant last mile logistics and storage business. Our completion services business operates in several of the most active basins in the continental United States including the Permian, the Marcellus Shale/Utica, the Eagle Ford, Mid-Continental, Haynesville, and the Bakken/Rockies.
To address evolving customer preferences for emissions-reducing equipment, we have invested in natural gas-powered equipment, including electric, direct drive, and dual fuel pumps, to replace legacy diesel completion services equipment.
Drilling Products
We serve the energy and mining markets by manufacturing and distributing drill bits throughout North America and internationally in over 30 countries. Our drilling equipment is used in oil and natural gas exploration and production and in mining operations. We have manufacturing and repair facilities located in Fort Worth, Texas, Leduc, Alberta and Saudi Arabia and repair facilities located in Argentina, Colombia and Oman.
Recent Developments in Market Conditions and Outlook — Commodity prices have historically been volatile but were relatively range-bound from the end of 2022 through the first quarter of 2025. The current demand for equipment and services remains impacted by macro conditions, including commodity prices, geopolitical environment, changes to international tariffs and
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trade policies, inflationary pressures, economic conditions in the United States and elsewhere, as well as customer consolidation and focus by exploration and production companies and service companies on capital returns. Subsequent to March 31, 2025, global economic conditions deteriorated, in part, because of recently enacted trade policies and tariffs implemented by the United States and other governments, as well as uncertainty regarding potential future changes to global trade policies and tariffs. Additionally, subsequent to March 31, 2025, several OPEC+ countries announced plans to phase out existing crude oil output cuts earlier than anticipated. These developments and geopolitical tensions have introduced increased uncertainty in global energy markets, which has contributed to a decline in our share price, lowered crude oil futures prices and increased uncertainty regarding the future economic environment in which we operate. The recent deterioration in macroeconomic conditions and the decline in our share price occurred after the balance sheet date and do not reflect conditions that existed as of March 31, 2025. Accordingly, these developments have not been reflected in the unaudited condensed consolidated financial statements for the three months ended March 31, 2025. While the full effects are yet to be determined, prolonged trade tensions and sustained lower crude oil futures prices could adversely affect our future outlook on activity and profitability. Oil prices averaged $71.78 per barrel in the first quarter of 2025, as compared to $70.73 per barrel in the fourth quarter of 2024, and closed at $63.48 per barrel on April 21, 2025. Natural gas prices (based on the Henry Hub Spot Market Price) averaged $4.14 per MMBtu in the first quarter of 2025 as compared to an average of $2.45 per MMBtu in the fourth quarter of 2024, and closed at $3.16 per MMBtu on April 21, 2025.
Our average active rig count in the United States for the first quarter of 2025 was 106 rigs. This was an increase from our average active rig count for the fourth quarter of 2024 of 105. Term contracts help support our operating rig count. Based on contracts in place in the United States as of April 24, 2025, we expect an average of 62 rigs operating under term contracts during the second quarter of 2025 and an average of 35 rigs operating under term contracts during the four quarters ending March 31, 2026.
We maintain a backlog of commitments for contract drilling services under term contracts, which we define as contracts with a duration of six months or more. Our contract drilling backlog in the United States as of March 31, 2025 was approximately $407 million. Approximately 9% of our total contract drilling backlog in the United States at March 31, 2025 is reasonably expected to remain at March 31, 2026. See Note 2 of Notes to unaudited condensed consolidated financial statements for additional information on backlog.
In our Drilling Services segment for the second quarter of 2025, we expect our average daily rig count to remain relatively steady compared to the first quarter. We expect adjusted gross profit within the Drilling Services segment to decline slightly, with the sequential change driven by a reduction in average contracted revenue as existing term contracts with more favorable pricing expire, as well as some normal seasonal increase in costs.
In our Completion Services segment for the second quarter of 2025, we currently expect activity to remain relatively steady as compared to activity levels at the end of the first quarter, although current oil prices may impact demand for completion services later in the second quarter. We expect second quarter Completion Services adjusted gross profit to decline slightly, sequentially.
In our Drilling Products segment for the second quarter of 2025, we expect sequential adjusted gross profit to remain relatively flat compared to the first quarter, with steady activity in the United States. We expect impacts from the normal seasonal spring breakup in Canada to be mostly offset by higher International revenue in the rest of the world.
Recent Developments in Debt Financing — On January 31, 2025, we entered into the Second Amended and Restated Credit Agreement with the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent, and the other parties thereto (the “Credit Agreement”). The Credit Agreement amended and restated our Amended and Restated Credit Agreement dated as of March 27, 2018 (as amended, restated, supplemented or otherwise modified at December 31, 2024, the “Prior Credit Agreement”). The commitments under the Credit Agreement are $500 million, and the loans and commitments under the Credit Agreement mature on January 31, 2030.
The Credit Agreement provides for a committed senior unsecured credit facility that permits aggregate revolving credit borrowings of up to $500 million, with a letter of credit sub-facility of $100 million and a swing line sub-facility that, at any time outstanding, is limited to the lesser of $50 million and the amount of the swing line provider’s unused commitment. Subject to customary conditions, we may request that the lenders’ aggregate commitments be increased by up to $200 million, not to exceed total commitments of $700 million. For a description of the Credit Agreement, see “Liquidity and Capital Resources” below.
As of March 31, 2025, we had no borrowings outstanding under our Credit Agreement. We had $2.0 million in letters of credit outstanding under the Credit Agreement at March 31, 2025 and, as a result, had available borrowing capacity of approximately $498 million at that date.
Impact on our Business from Oil and Natural Gas Prices and Other Factors — Our revenues, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas, expectations about future prices, and upon our customers’ ability to access, and willingness to deploy, capital to fund their operating and capital expenditures. During periods of improved oil and natural
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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, or willingness to deploy, capital, the demand for our services generally weakens, and we experience downward pressure on pricing for our services. Even during periods of historically moderate or high prices for oil and natural gas, companies exploring for oil and natural gas may cancel or curtail programs or reduce their levels of capital expenditures for exploration and production for a variety of reasons, including the depletion of capital expenditure budgets and/or meeting annual drilling and completion targets, which could reduce demand for our services. We may also be impacted by delayed customer payments and payment defaults associated with customer liquidity issues and bankruptcies.
The 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. 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 businesses, supplier delays and various other factors that could materially adversely affect our business, financial condition, cash flows and results of operations. Please see Item 1A of our Annual Report.
For the three months ended March 31, 2025, December 31, 2024, and March 31, 2024 our operating revenues consisted of the following (dollars in thousands):

| Three Months Ended
| March 31, |  | December 31, |  |  |  | March 31,
| 2025 |  | 2024 |  |  |  | 2024
Drilling Services | $ | 412,860 |  |  | 32.2 | % |  | $ | 408,385 |  |  | 35.1 | % |  |  |  |  |  | $ | 457,573 |  |  | 30.3 | %
Completion Services | 766,080 |  |  | 59.8 | % |  | 650,848 |  |  | 56.0 | % |  |  |  |  |  | 944,997 |  |  | 62.6 | %
Drilling Products | 85,663 |  |  | 6.7 | % |  | 86,522 |  |  | 7.4 | % |  |  |  |  |  | 89,973 |  |  | 6.0 | %
Other | 15,934 |  |  | 1.3 | % |  | 16,380 |  |  | 1.5 | % |  |  |  |  |  | 17,817 |  |  | 1.1 | %
| $ | 1,280,537 |  |  | 100.0 | % |  | $ | 1,162,135 |  |  | 100.0 | % |  |  |  |  |  | $ | 1,510,360 |  |  | 100.0 | %

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Results of Operations
The following tables summarize results of operations by business segment for the three months ended March 31, 2025, December 31, 2024, and March 31, 2024:

|  | Three Months Ended |  |  |  |
|  | March 31, |  | December 31, |  | March 31, |  | % Change
Drilling Services |  | 2025 |  | 2024 |  | 2024 |  | Sequential |  | Year-over-year
|  | (dollars in thousands) |  |  |  |
Revenues |  | $ | 412,860 |  |  | $ | 408,385 |  |  | $ | 457,573 |  |  | 1.1 | % |  | (9.8) | %
Direct operating costs |  | 247,629 |  |  | 245,480 |  |  | 271,737 |  |  | 0.9 | % |  | (8.9) | %
Adjusted gross profit (1) |  | 165,231 |  |  | 162,905 |  |  | 185,836 |  |  | 1.4 | % |  | (11.1) | %
Selling, general and administrative |  | 3,945 |  |  | 4,741 |  |  | 3,879 |  |  | (16.8) | % |  | 1.7 | %
Depreciation, amortization and impairment |  | 84,972 |  |  | 85,174 |  |  | 92,345 |  |  | (0.2) | % |  | (8.0) | %
Operating income |  | $ | 76,314 |  |  | $ | 72,990 |  |  | $ | 89,612 |  |  | 4.6 | % |  | (14.8) | %
Capital expenditures |  | $ | 73,458 |  |  | $ | 54,321 |  |  | $ | 82,793 |  |  | 35.2 | % |  | (11.3) | %
Operating days – U.S. (2) |  | 9,573 |  |  | 9,617 |  |  | 11,024 |  |  | (0.5) | % |  | (13.2) | %
Average revenue per operating day – U.S. (2) |  | $ | 35.72 |  |  | $ | 35.29 |  |  | $ | 35.68 |  |  | 1.2 | % |  | 0.1 | %
Average direct operating costs per operating day – U.S. (2) |  | $ | 19.55 |  |  | $ | 19.57 |  |  | $ | 19.51 |  |  | (0.1) | % |  | 0.2 | %
Average adjusted gross profit per operating day – U.S. (2) |  | $ | 16.17 |  |  | $ | 15.72 |  |  | $ | 16.17 |  |  | 2.9 | % |  | 0.0 | %

(1)Adjusted gross profit is defined as revenues less direct operating costs (excluding depreciation, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross profit to adjusted gross profit by segment.
(2)Operational data relates to our contract drilling business. A rig is considered to be operating if it is earning revenue pursuant to a contract on a given day.
Sequential quarter comparison
Generally, the revenues in our drilling services segment are most impacted by two primary factors: our contract drilling day rates and our average number of rigs operating.
Revenues and direct operating costs, both on a total and per operating day basis, were relatively flat between sequential quarters.
Capital expenditures increased primarily due to spending related to maintenance capital and the timing of order placement that more heavily impacted the first quarter of 2025.
Year-over-year quarter comparison
Revenues and direct operating costs decreased due to a decrease in operating days for our U.S. contract drilling operations.
The decrease in depreciation, amortization and impairment expense was attributable to a lower depreciable asset base in the first quarter of 2025, in part, due to the abandonment of 42 legacy non-super-spec rigs and equipment in the third quarter of 2024.
Capital expenditures decreased primarily due to reduced investment in our ancillary drilling services not included within our contract drilling business.
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|  | Three Months Ended |  |  |  |
|  | March 31, |  | December 31, |  | March 31, |  | % Change
Completion Services |  | 2025 |  | 2024 |  | 2024 |  | Sequential |  | Year-over-year
|  | (dollars in thousands) |  |  |  |
Revenues |  | $ | 766,080 |  |  | $ | 650,848 |  |  | $ | 944,997 |  |  | 17.7 | % |  | (18.9) | %
Direct operating costs |  | 657,681 |  |  | 555,527 |  |  | 745,594 |  |  | 18.4 | % |  | (11.8) | %
Adjusted gross profit (1) |  | 108,399 |  |  | 95,321 |  |  | 199,403 |  |  | 13.7 | % |  | (45.6) | %
Selling, general and administrative |  | 11,409 |  |  | 9,703 |  |  | 10,964 |  |  | 17.6 | % |  | 4.1 | %
Depreciation, amortization and impairment |  | 115,826 |  |  | 135,852 |  |  | 148,680 |  |  | (14.7) | % |  | (22.1) | %
Other operating income, net |  | — |  |  | — |  |  | (9,870) |  |  | NA |  | (100.0) | %
Operating income (loss) |  | $ | (18,836) |  |  | $ | (50,234) |  |  | $ | 49,629 |  |  | (62.5) | % |  | NA
Capital expenditures |  | $ | 62,173 |  |  | $ | 61,469 |  |  | $ | 123,377 |  |  | 1.1 | % |  | (49.6) | %

(1)Adjusted gross profit is defined as revenues less direct operating costs (excluding depreciation, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross profit to adjusted gross profit by segment.
Sequential quarter comparison
Completion services revenues and direct operating costs increased primarily due to seasonal recovery as customer budgets reset in the first quarter. The higher revenues and direct operating costs were primarily from our fracturing operations, which increased $86 million and $82 million, or 17% and 18%, respectively. The increases were primarily activity driven, with pumping hours increasing 23% during the first quarter of 2025.
Depreciation, amortization and impairment expense decreased primarily due to $20.8 million of accelerated depreciation recognized in the fourth quarter of 2024.
Year-over-year quarter comparison
Completion services revenues and direct operating costs decreased primarily due to lower activity in our fracturing operations. Revenues and direct operating costs from our fracturing operations decreased by $170 million and $84 million, or 21% and 13%, respectively.
Depreciation, amortization and impairment expense decreased primarily due to fewer capital additions placed in service relative to asset retirements between the periods.
Other operating income, net in the first quarter of 2024 was due to a gain on legal settlement.
We reduced capital expenditures in response to the changing macroeconomic conditions between the periods.

|  | Three Months Ended |  |  |  |
|  | March 31, |  | December 31, |  | March 31, |  | % Change
Drilling Products |  | 2025 |  | 2024 |  | 2024 |  | Sequential |  | Year-over-year
|  | (dollars in thousands) |  |  |  |
Revenues |  | $ | 85,663 |  |  | $ | 86,522 |  |  | $ | 89,973 |  |  | (1.0) | % |  | (4.8) | %
Direct operating costs |  | 46,940 |  |  | 49,186 |  |  | 48,630 |  |  | (4.6) | % |  | (3.5) | %
Adjusted gross profit (1) |  | 38,723 |  |  | 37,336 |  |  | 41,343 |  |  | 3.7 | % |  | (6.3) | %
Selling, general and administrative |  | 9,119 |  |  | 10,209 |  |  | 7,661 |  |  | (10.7) | % |  | 19.0 | %
Depreciation, amortization and impairment |  | 22,876 |  |  | 27,328 |  |  | 27,182 |  |  | (16.3) | % |  | (15.8) | %
Operating income (loss) |  | $ | 6,728 |  |  | $ | (201) |  |  | $ | 6,500 |  |  | NA |  | 3.5 | %
Capital expenditures |  | $ | 18,222 |  |  | $ | 15,834 |  |  | $ | 15,586 |  |  | 15.1 | % |  | 16.9 | %

(1)Adjusted gross profit is defined as revenues less direct operating costs (excluding depreciation, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross profit to adjusted gross profit by segment.
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Sequential quarter comparison
Revenues and direct operating costs were relatively flat between sequential quarters.
Direct operating costs and depreciation, amortization and impairment expense were approximately $0.6 million and $2.3 million higher than they would have otherwise been for the three months ended March 31, 2025, respectively, as a result of the step up to fair value of our drill bits in accordance with purchase accounting. For the three months ended December 31, 2024, direct operating costs and depreciation, amortization and impairment expense were approximately $3.1 million and $6.1 million higher than they would have otherwise been, respectively, as a result of the step up to fair value of our drill bits.
Year-over-year quarter comparison
Revenues and direct operating costs were relatively flat between the quarters.
Direct operating costs and depreciation, amortization and impairment expense were approximately $0.6 million and $2.3 million higher than they would have otherwise been for the three months ended March 31, 2025, respectively, as a result of the step up to fair value of our drill bits in accordance with purchase accounting. For the three months ended March 31, 2024, direct operating costs and depreciation, amortization and impairment were approximately $2.2 million and $5.8 million higher, respectively, as a result of the step up to fair value of our drill bits.

|  | Three Months Ended |  |  |  |
|  | March 31, |  | December 31, |  | March 31, |  | % Change
Other |  | 2025 |  | 2024 |  | 2024 |  | Sequential |  | Year-over-year
|  | (dollars in thousands) |  |  |  |
Revenues |  | $ | 15,934 |  |  | $ | 16,380 |  |  | $ | 17,817 |  |  | (2.7) | % |  | (10.6) | %
Direct operating costs |  | 9,164 |  |  | 9,466 |  | 11,178 |  | (3.2) | % |  | (18.0) | %
Adjusted gross profit (1) |  | 6,770 |  |  | 6,914 |  | 6,639 |  | (2.1) | % |  | 2.0 | %
Selling, general and administrative |  | 204 |  |  | 59 |  | 240 |  | 245.8 | % |  | (15.0) | %
Depreciation, depletion, amortization and impairment |  | 6,336 |  |  | 4,790 |  | 5,411 |  | 32.3 | % |  | 17.1 | %
Operating income |  | $ | 230 |  |  | $ | 2,065 |  |  | $ | 988 |  |  | (88.9) | % |  | (76.7) | %
Capital expenditures |  | $ | 3,596 |  |  | $ | 2,894 |  |  | $ | 3,797 |  |  | 24.3 | % |  | (5.3) | %

(1)Adjusted gross profit is defined as revenues less direct operating costs (excluding depreciation, depletion, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross profit to adjusted gross profit by segment.
Sequential quarter comparison
Revenues and direct operating costs were relatively flat between sequential quarters.
Depreciation, depletion, amortization and impairment expense increased primarily due to a $1.7 million impairment charge recorded in our oil and natural gas properties business during the first quarter of 2025.
Year-over-year quarter comparison
Revenues and direct operating costs decreased primarily due to lower activity as a result of lower crude oil and natural gas market prices. Oil prices averaged $71.78 per barrel in the first quarter of 2025, as compared to $77.50 per barrel in the first quarter of 2024.
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|  | Three Months Ended |  |  |  |
|  | March 31, |  | December 31, |  | March 31, |  | % Change
Corporate |  | 2025 |  | 2024 |  | 2024 |  | Sequential |  | Year-over-year
|  | (dollars in thousands) |  |  |  |
Selling, general and administrative |  | $ | 42,253 |  |  | $ | 48,367 |  |  | $ | 42,240 |  |  | (12.6) | % |  | 0.0 | %
Merger and integration expense |  | $ | 432 |  |  | $ | 3,460 |  |  | $ | 12,233 |  |  | (87.5) | % |  | (96.5) | %
Depreciation |  | $ | 1,856 |  |  | $ | 1,455 |  |  | $ | 1,338 |  |  | 27.6 | % |  | 38.7 | %
Other operating expense, net |  | $ | 2,950 |  |  | $ | 2,673 |  |  | $ | 3,919 |  |  | 10.4 | % |  | (24.7) | %
Interest income |  | $ | 1,464 |  |  | $ | 928 |  |  | $ | 2,189 |  |  | 57.8 | % |  | (33.1) | %
Interest expense, net of amount capitalized |  | $ | (17,697) |  |  | $ | (17,725) |  |  | $ | (18,335) |  |  | (0.2) | % |  | (3.5) | %
Other income (expense) |  | $ | 1,968 |  |  | $ | (1,333) |  |  | $ | 850 |  |  | NA |  | 131.5 | %
Capital expenditures |  | $ | 4,382 |  |  | $ | 5,832 |  |  | $ | 1,388 |  |  | (24.9) | % |  | 215.7 | %

Sequential quarter comparison
Selling, general and administrative expense decreased primarily due to certain severance costs incurred in the fourth quarter that did not recur as well as a continued focus on cost reduction efforts.
Other income (expense) during the first quarter of 2025 included $1.4 million of income from an unconsolidated joint venture.
Year-over-year quarter comparison
Merger and integration expense decreased due to the passage of time since closing the NexTier merger and the Ulterra acquisition in third quarter of 2023.
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 GAAP and tax accounting.
Our effective income tax rate for the three months ended March 31, 2025 was 51.9%, compared with (3.9)% for the three months ended December 31, 2024. The difference in effective income tax rates between the periods was primarily attributable to the impact of valuation allowances on deferred tax assets between periods, as well as the impact of goodwill impairments and permanent differences against earnings between periods.
Our effective income tax rate for the three months ended March 31, 2025 was 51.9%, compared with 27.9% for the three months ended March 31, 2024. The difference in effective income tax rates between the periods was primarily attributable to the impact of permanent differences against earnings between periods.
We continue to monitor income tax developments in the United States and other countries where we have legal entities. 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
Our primary sources of liquidity are cash and cash equivalents, availability under our Credit Agreement and cash provided by operating activities. As of March 31, 2025, we had approximately $499 million in working capital, including $223 million of cash and cash equivalents, and approximately $498 million available under our Credit Agreement.
On January 31, 2025, we entered into the Credit Agreement, which amended and restated the Prior Credit Agreement. The commitments under the Credit Agreement are $500 million, and the loans and commitments under the Credit Agreement mature on January 31, 2030.
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The Credit Agreement provides for a committed senior unsecured credit facility that permits aggregate revolving credit borrowings of up to $500 million, with a letter of credit sub-facility of $100 million and a swing line sub-facility that, at any time outstanding, is limited to the lesser of $50 million and the amount of the swing line provider’s unused commitment. Subject to customary conditions, we may request that the lenders’ aggregate commitments be increased by up to $200 million, not to exceed total commitments of $700 million.
Loans under the Credit Agreement bear interest by reference, at our election, to the SOFR rate (plus a 0.10% per annum adjustment) or base rate, in each case subject to a 0% floor. The applicable margin on SOFR rate loans varies from 1.25% to 2.25% and the applicable margin on base rate loans varies from 0.25% to 1.25%, in each case determined based on our credit rating. As of March 31, 2025, the applicable margin on SOFR 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 SOFR 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 0.15% to 0.35% 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, which does not qualify for certain limited exceptions and is otherwise, in the aggregate with all other similar debt, in excess of Priority Debt (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 grant liens and on the ability of each of our non-guarantor subsidiaries to incur debt. 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 generally 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 both credit rating agencies. The Credit Agreement also requires that our total debt to capitalization ratio, expressed as a percentage, not exceed 50% as of the last day of each fiscal quarter. 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 March 31, 2025.
On March 16, 2015, we entered into a Reimbursement Agreement (as amended from time to time, 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 March 31, 2025, we had $38.8 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 of our letters of credit issued thereunder. 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 Prime rate plus 2.00% 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. A letter of credit fee is payable by us equal to 1.50% times the amount of outstanding letters of credit.
We have also agreed that if obligations under the Credit Agreement are secured by liens on any of our or our subsidiaries’ property, then our reimbursement obligations and (to the extent similar obligations would be secured under the Credit Agreement) other obligations under the Reimbursement Agreement and any letters of credit will be equally and ratably secured by all property subject to such liens securing the Credit Agreement.
Pursuant to a Continuing Guaranty dated as of March 16, 2015, our payment obligations under the Reimbursement Agreement are jointly and severally guaranteed as to payment and not as to collection by our subsidiaries that from time to time guarantee payment under the Credit Agreement. None of our subsidiaries are currently required to guarantee payment under the Credit Agreement.
We had $42.8 million of outstanding letters of credit at March 31, 2025, which was comprised of $38.8 million outstanding under the Reimbursement Agreement, $2.0 million outstanding under the Credit Agreement, and $2.0 million outstanding with financial institutions providing for short-term borrowing capacity, overdraft protection and bonding requirements. We maintain these letters of credit primarily for the benefit of various insurance companies as collateral for retrospective premiums and retained losses
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which could become payable under terms of the underlying insurance contracts and compliance with contractual obligations. These letters of credit expire annually at various times during the year and are typically renewed. As of March 31, 2025, no amounts had been drawn under the letters of credit. As of March 31, 2025, we had $35.0 million in surety bond exposure issued as financial assurance on an insurance agreement.
Our outstanding long-term debt at March 31, 2025 was $1.2 billion and consisted of $483 million of our 2028 Notes, $345 million of our 2029 Notes, $400 million of our 2033 Notes and $3.2 million of secured equipment financing term loans. We were in compliance with all covenants under the associated agreements and indentures at March 31, 2025.
For a full description of the Credit Agreement, the Reimbursement Agreement, the 2028 Notes, the 2029 Notes, and the 2033 Notes, see Note 8 of Notes to unaudited condensed consolidated financial statements.
Cash Requirements
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, pay cash dividends and repurchase our common stock and senior notes for at least the next 12 months.
If we pursue other opportunities 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.
The majority of our capital expenditures are expected to be used for normal, recurring items necessary to support our business. A portion of our capital expenditures can be adjusted and managed by us to match market demand and activity levels.
We anticipate $44.7 million of expenditures for the remainder of 2025 related to various contractual obligations such as certain commitments to purchase proppants and lease liabilities.
As of March 31, 2025, we had working capital of $499 million, including cash, cash equivalents and restricted cash of $225 million, compared to working capital of $453 million, including cash, cash equivalents and restricted cash of $241 million, at December 31, 2024.
During the three months ended March 31, 2025, our sources of cash flow included:
•$208 million from operating activities, and
•$4.3 million in proceeds from the disposal of property and equipment.
During the three months ended March 31, 2025, our uses of cash flow included:
•$162 million to make capital expenditures for the betterment and refurbishment of drilling services and completion services equipment and, to a much lesser extent, equipment for our other businesses, to acquire and procure equipment to support our drilling services, completion services, drilling products, and other operations,
•$20.3 million for repurchases of our common stock,
•$30.9 million to pay dividends on our common stock,
•$2.6 million for payments related to finance leases, and
•$12.1 million for other investing and financing activities.
We paid cash dividends during the three months ended March 31, 2025 as follows:

| Per Share |  | Total
|  |  | (in thousands)
Paid on March 17, 2025 | $ | 0.08 |  |  | $ | 30,877 |

On April 23, 2025, our Board of Directors approved a cash dividend on our common stock in the amount of $0.08 per share to be paid on June 16, 2025 to holders of record as of June 2, 2025. The amount and timing of all future dividend payments, if any, are subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of our debt agreements and other factors. Our Board of Directors may, without advance notice, reduce or suspend
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our dividend for any reason, including to improve our financial flexibility and position our company for long-term success. There can be no assurance that we will pay a dividend in the future.
We may, at any time and from time to time, seek to retire or purchase our outstanding debt for cash through open-market purchases, privately negotiated transactions, redemptions or otherwise. Such repurchases, if any, will be upon such terms and at such prices as we may determine, and will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
In September 2013, our Board of Directors approved a stock buyback program. In February 2024, our Board of Directors approved an increase of the authorization under the stock buyback program to allow for an aggregate of $1.0 billion of future share repurchases. All purchases executed to date have been through open market transactions. Purchases under the buyback 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 March 31, 2025, we had remaining authorization to purchase approximately $741 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 three months ended March 31, 2025 were as follows (dollars in thousands):

| Shares |  | Cost
Treasury shares at beginning of period | 133,440,028 |  | $ | 1,951,067 |
Purchases pursuant to stock buyback program | 2,078,723 |  |  | 18,062 |
Acquisitions pursuant to long-term incentive plans (1) | 258,558 |  |  | 2,233 |
Treasury shares at end of period | 135,777,309 |  | $ | 1,971,362 |

(1)We withheld 258,558 shares during the three months ended March 31, 2025 with respect to employees’ tax withholding obligations upon the vesting of restricted stock units. These shares were acquired at fair market value. These acquisitions were made pursuant to the terms of the Patterson-UTI Energy, Inc. 2021 Long-Term Incentive Plan, as amended and the NexTier Oilfield Solutions Inc. Equity and Incentive Award Plan, and not pursuant to the stock buyback program.
Commitments — As of March 31, 2025, we had commitments to purchase major equipment totaling approximately $111 million. Our completion services segment has entered into agreements to purchase minimum quantities of proppants from certain vendors. As of March 31, 2025, the remaining minimum obligation under these agreements was approximately $18.7 million, of which approximately $13.6 million and $5.1 million relate to the remainder of 2025 and 2026, respectively.
See Note 9 of Notes to unaudited condensed consolidated financial statements for additional information on our current commitments and contingencies as of March 31, 2025.
Operating lease liabilities totaled $45.7 million and finance lease liabilities totaled $23.0 million as of March 31, 2025.
Trading and Investing — We have not engaged in trading activities that include high-risk securities, such as derivatives and non-exchange traded contracts. We invest cash primarily in highly liquid, short-term investments such as overnight deposits and money market accounts.
Non-GAAP Financial Measures
Adjusted EBITDA
Adjusted earnings before interest, taxes, depreciation and amortization (“Adjusted EBITDA”) is not defined by accounting principles generally accepted in the United States of America (“GAAP”). We define Adjusted EBITDA as net income (loss) plus income tax expense (benefit), net interest expense, depreciation, depletion, amortization and impairment expense (including impairment of goodwill) and merger and integration expense. We present Adjusted EBITDA as a supplemental disclosure 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 GAAP measure of net income (loss). Our computations of Adjusted EBITDA may not be the same
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as similarly titled measures of other companies. Set forth below is a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measure of net income (loss).

| Three Months Ended
| March 31, |  | December 31, |  | March 31, |  |
| 2025 |  | 2024 |  | 2024 |  |  |  |
| (in thousands)
Net income (loss) | $ | 1,290 |  |  | $ | (51,392) |  |  | $ | 51,706 |  |  |  |  |
Income tax expense | 1,390 |  |  | 1,927 |  |  | 19,997 |  |  |  |  |
Net interest expense | 16,233 |  |  | 16,797 |  |  | 16,146 |  |  |  |  |
Depreciation, depletion, amortization and impairment | 231,866 |  |  | 254,599 |  |  | 274,956 |  |  |  |  |
Merger and integration expense | 432 |  |  | 3,460 |  |  | 12,233 |  |  |  |  |
Adjusted EBITDA | $ | 251,211 |  |  | $ | 225,391 |  |  | $ | 375,038 |  |  |  |  |

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

| Drilling Services |  | Completion Services |  | Drilling Products |  | Other
| (in thousands)
For the three months ended March 31, 2025 |  |  |  |  |  |  |
Revenues | $ | 412,860 |  |  | $ | 766,080 |  |  | $ | 85,663 |  |  | $ | 15,934 |
Less direct operating costs | (247,629) |  |  | (657,681) |  |  | (46,940) |  |  | (9,164) |
Less depreciation, depletion, amortization and impairment | (84,972) |  |  | (115,826) |  |  | (22,876) |  |  | (6,336) |
GAAP gross profit (loss) | 80,259 |  |  | (7,427) |  |  | 15,847 |  |  | 434 |
Depreciation, depletion, amortization and impairment | 84,972 |  |  | 115,826 |  |  | 22,876 |  |  | 6,336 |
Adjusted gross profit | $ | 165,231 |  |  | $ | 108,399 |  |  | $ | 38,723 |  |  | $ | 6,770 |
For the three months ended December 31, 2024 |  |  |  |  |  |  |
Revenues | $ | 408,385 |  |  | $ | 650,848 |  |  | $ | 86,522 |  |  | $ | 16,380 |
Less direct operating costs | (245,480) |  |  | (555,527) |  |  | (49,186) |  |  | (9,466) |
Less depreciation, depletion, amortization and impairment | (85,174) |  |  | (135,852) |  |  | (27,328) |  |  | (4,790) |
GAAP gross profit (loss) | 77,731 |  |  | (40,531) |  |  | 10,008 |  |  | 2,124 |
Depreciation, depletion, amortization and impairment | 85,174 |  |  | 135,852 |  |  | 27,328 |  |  | 4,790 |
Adjusted gross profit | $ | 162,905 |  |  | $ | 95,321 |  |  | $ | 37,336 |  |  | $ | 6,914 |
For the three months ended March 31, 2024 |  |  |  |  |  |  |
Revenues | $ | 457,573 |  |  | $ | 944,997 |  |  | $ | 89,973 |  |  | $ | 17,817 |
Less direct operating costs | (271,737) |  |  | (745,594) |  |  | (48,630) |  |  | (11,178) |
Less depreciation, depletion, amortization and impairment | (92,345) |  |  | (148,680) |  |  | (27,182) |  |  | (5,411) |
GAAP gross profit | 93,491 |  |  | 50,723 |  |  | 14,161 |  |  | 1,228 |
Depreciation, depletion, amortization and impairment | 92,345 |  |  | 148,680 |  |  | 27,182 |  |  | 5,411 |
Adjusted gross profit | $ | 185,836 |  |  | $ | 199,403 |  |  | $ | 41,343 |  |  | $ | 6,639 |

Critical Accounting Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make certain estimates and assumptions that affect the reported amounts of assets and
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liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from such estimates. There have been no material changes to our critical accounting estimates previously disclosed in Item 7 of our Annual Report.
Recently Issued Accounting Standards
See Note 1 of Notes to unaudited condensed consolidated financial statements for a discussion of the impact of recently issued accounting standards.
Volatility of Oil and Natural Gas Prices and its Impact on Operations and Financial Condition
Our revenues, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas and expectations about future prices, and upon our customers’ ability to access, and willingness to deploy, capital to fund their operating and capital expenditures. Commodity prices have historically been volatile, but were relatively range-bound from the end of 2022 through the first quarter of 2025. The current demand for equipment and services remains impacted by macro conditions, including commodity prices, geopolitical environment, changes to international tariffs and trade policies, inflationary pressures, economic conditions in the United States and elsewhere, as well as customer consolidation and focus by exploration and production companies and service companies on capital returns. Subsequent to March 31, 2025, global economic conditions deteriorated, in part, because of recently enacted trade policies and tariffs implemented by the United States and other governments, as well as uncertainty regarding potential future changes to global trade policies and tariffs. Additionally, subsequent to March 31, 2025, several OPEC+ countries announced plans to phase out existing crude oil output cuts earlier than anticipated. These developments and geopolitical tensions have introduced increased uncertainty in global energy markets, which has contributed to a decline in our share price, lowered crude oil futures prices and increased uncertainty regarding the future economic environment in which we operate. The recent deterioration in macroeconomic conditions and the decline in our share price occurred after the balance sheet date and do not reflect conditions that existed as of March 31, 2025. Accordingly, these developments have not been reflected in the unaudited condensed consolidated financial statements for the three months ended March 31, 2025. While the full effects are yet to be determined, prolonged trade tensions and sustained lower crude oil futures prices could adversely affect our future outlook on activity and profitability. Oil prices averaged $71.78 per barrel in the first quarter of 2025, as compared to $70.73 per barrel in the fourth quarter of 2024, and closed at $63.48 per barrel on April 21, 2025. Natural gas prices (based on the Henry Hub Spot Market Price) averaged $4.14 per MMBtu in the first quarter of 2025 as compared to an average of $2.45 per MMBtu in the fourth quarter of 2024, and closed at $3.16 per MMBtu on April 21, 2025.
In light of these and other factors, we expect oil and natural gas prices to continue to be unpredictable 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, and willingness to deploy, 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, including the depletion of capital expenditure budgets and/or meeting annual drilling and completion targets, which could reduce demand for our services.
Impact of Inflation and Trade Policies
Moderate inflationary pressures and uncertainty regarding recently enacted and potential future changes to international tariffs and trade policies have contributed, or may contribute, to increases in the cost of certain goods, services, and labor. While the full effects are yet to be determined, prolonged trade tensions could, among other things, increase the costs of certain products used in our businesses, such as drill pipe, parts, and electronics. We continue to actively monitor market trends primarily related to sourcing of labor, supplies and equipment.
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ITEM 3. Quantitative and Qualitative Disclosures About Market Risk
We may be exposed to certain market risks arising from the use of financial instruments in the ordinary course of business. For quantitative and qualitative disclosures about market risk, see Part II, Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” in our Annual Report. There have been no material changes in our exposure to market risk.
As of March 31, 2025, we would have had exposure to interest rate market risk associated with any outstanding borrowings and letters of credit that we had under the Credit Agreement and amounts owed under the Reimbursement Agreement.
Loans under the Credit Agreement bear interest by reference, at our election, to the SOFR rate (plus a 0.10% per annum adjustment) or base rate, in each case subject to a 0% floor. The applicable margin on SOFR rate loans varies from 1.25% to 2.25% and the applicable margin on base rate loans varies from 0.25% to 1.25%, in each case determined based on our credit rating. As of March 31, 2025, the applicable margin on SOFR 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 SOFR 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 0.15% to 0.35% based on our credit rating. As of March 31, 2025, we had $2.0 million in letters of credit outstanding under the Credit Agreement and, as a result, had available borrowing capacity of approximately $498 million at that date.
Under the terms of the Reimbursement Agreement, we will reimburse Scotiabank on demand for any amounts that Scotiabank has disbursed under any of our letters of credit issued thereunder. 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 Prime rate plus 2.00% per annum.
Our functional currency is primarily the U.S. dollar. Approximately 98% of our revenue during the first quarter of 2025 was denominated in U.S. dollars. As such, we do not believe we are significantly exposed to foreign currency exchange rate risk. However, a portion of our revenues in foreign countries are denominated in U.S. dollars, and therefore, changes in foreign currency exchange rates impact our earnings to the extent that costs associated with those U.S. dollar revenues are denominated in the local currency. Similarly, a portion of our revenues are denominated in foreign currencies, but have associated U.S. dollar costs, which also give rise to foreign currency exchange rate exposure.
The carrying values of cash, cash equivalents and restricted cash, trade receivables and accounts payable approximate fair value due to the short-term maturity of these items.
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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 March 31, 2025.
Changes in Internal Control Over Financial Reporting —There were no changes in our internal control over financial reporting during our most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act.
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PART II — OTHER INFORMATION
ITEM 1. Legal Proceedings
Certain subsidiaries we acquired in the Ulterra acquisition are defendants in a claim brought by a subsidiary of NOV Inc. alleging breach of a license agreement related to certain patents. Such subsidiaries have asserted defenses to the claim and are defending vigorously against this claim.
On February 6, 2023, Grant Prideco, Inc., ReedHycalog UK, Ltd. ReedHycalog, LP, National Oilwell Varco, LP (“NOV”) sued Ulterra Drilling Technologies, LP (“Ulterra”) and several other companies in Texas state court. NOV seeks a declaration that United States Patent No. 8,721,752 (the “’752 Patent”) is a “Licensed RH Patent” per the terms of a license agreement between Ulterra and NOV. NOV also alleges a breach of contract based on the license agreement between NOV and Ulterra and seeks allegedly owed royalties since October 22, 2021. NOV also seeks attorney’s fees.
On February 27, 2023, Ulterra filed a plea to the jurisdiction, and subject thereto, an answer, affirmative defenses and counterclaims. Ulterra’s counterclaims include: (i) declaratory judgments of non-infringement of U.S. Pat. No. 7,568,534 and the ’752 patent; (ii) a declaratory judgment of no royalties after Oct. 22, 2021; (iii) a declaratory judgment that certain other identified patents are expired and therefore not infringed after Oct. 22, 2021; and (iv) a declaratory judgment of no breach of contract. On the same day, Ulterra filed a notice of removal in federal court for the Southern District of Texas, Houston Division (SDTX 4:23-cv-00730), as well as a corresponding notice in Texas state court. NOV moved to dismiss and remand the case back to state court. On February 17, 2024, the Court denied NOV’s motion. On March 19, 2024, Ulterra moved for judgment on the pleadings regarding its declaratory judgment that certain other identified patents are expired and therefore not infringed after October 22, 2021. On February 13, 2025, the motion was granted in part and denied in part.
Discovery is closed and dispositive motions are fully briefed. Trial is currently scheduled for October 27, 2025. An unfavorable judgment or resolution of this claim not covered by indemnity could have a material impact on our financial results.
Additionally, we are party to various other 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.
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 March 31, 2025.

Period Covered |  | Total Number of Shares Purchased(1) |  | Average Price Paid per Share |  | Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs |  | Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs (in thousands) (2)
January 2025 |  | 1,444,440 |  | $ | 8.71 |  |  | 1,288,736 |  | $ | 747,693 |
February 2025 |  | 886,656 |  | $ | 8.65 |  |  | 789,987 |  | $ | 740,872 |
March 2025 |  | 6,185 |  | $ | 7.94 |  |  | — |  | $ | 740,872 |
Total |  | 2,337,281 |  |  |  | 2,078,723 |  |

(1)We withheld 258,558 shares during the first quarter of 2025 with respect to employees’ tax withholding obligations upon the vesting of restricted stock units. These shares were acquired at fair market value. These acquisitions were made pursuant to the terms of the Patterson-UTI Energy, Inc. 2021 Long-Term Incentive Plan, as amended and the NexTier Oilfield Solutions Inc. Equity and Incentive Award Plan, and not pursuant to the stock buyback program.
(2)In September 2013, our Board of Directors approved a stock buyback program. In February 2024, our Board of Directors approved an increase of the authorization under the stock buyback program to allow for an aggregate of $1.0 billion of future share repurchases. All purchases executed to date have been through open market transactions. Purchases under the buyback 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.
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ITEM 5. Other Information
(c)During the three months ended March 31, 2025, certain of our officers and directors listed below adopted or terminated trading arrangements for the sale of shares of our common stock in amounts and prices determined in accordance with a formula set forth in each such plan:

|  |  |  |  |  |  | Plans |  |  |  |
Name and Title |  | Action |  | Date |  | Rule 10b5-1 |  | Non-Rule 10b5-1 |  | Number of Shares to be sold |  | Expiration
James C. Stewart | Director |  | Adoption |  | March 17, 2025 |  | X |  |  |  | 207,000 |  | June 30, 2026

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ITEM 6. Exhibits
The following exhibits are filed herewith or incorporated by reference, as indicated:

3.1 | Restated Certificate of Incorporation of Patterson-UTI Energy, Inc., dated as of June 6, 2024 (filed June 6, 2024 as Exhibit 4.1 to our Registration Statement on Form S-8 and incorporated herein by reference).
3.2 | Amended and Restated Bylaws of Patterson-UTI Energy, Inc., effective June 14, 2023 (filed June 15, 2023 as Exhibit 3.1 to our Current Report on Form 8-K and incorporated herein by reference).
10.1 | Second Amended and Restated Credit Agreement, dated January 31, 2025, by and among Patterson-UTI Energy, Inc., Wells Fargo Bank, National Association, as administrative agent, letter of credit issuer, swing line lender and a lender and each of the other letter of credit issuers and lenders party thereto with the lenders party thereto (filed February 3, 2025 as Exhibit 10.1 to our Current Report on Form 8-K and incorporated herein by reference).
31.1* | Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended.
31.2* | Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended.
32.1** | Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 USC Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS* | Inline XBRL Instance Document – the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH* | Inline XBRL Taxonomy Extension Schema Document
101.CAL* | Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF* | Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB* | Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE* | Inline XBRL Taxonomy Extension Presentation Linkbase Document
104 | The cover page from our Quarterly Report on Form 10-Q for the quarter ended March 31, 2025, has been formatted in Inline XBRL.

* | filed herewith.
** | furnished herewith.
+ | management contact or compensatory plan.

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

| PATTERSON-UTI ENERGY, INC.
| By: | /s/ C. Andrew Smith
|  | C. Andrew Smith
|  | Executive Vice President and
|  | Chief Financial Officer
|  | (Principal Financial Officer and Duly Authorized Officer)
Date: April 29, 2025 |  |

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