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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-K

(Mark One)

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

For the fiscal year ended December 31, 2024
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)

Registrant’s telephone number, including area code:
(281) 765-7100
Securities registered pursuant to Section 12(b) of the Act:

Title of each class |  | Trading Symbol(s) |  | Name of each exchange on which registered
Common Stock, $0.01 Par Value |  | PTEN |  | The Nasdaq Global Select Market

Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x or No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o or No x
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 x 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 (§ 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 x or 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 | x |  | 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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. x
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. o
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No x
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2024, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $4.0 billion, calculated by reference to the closing price of $10.36 for the common stock on the Nasdaq Global Select Market on that date.
As of February 5, 2025, the registrant had outstanding 386,390,297 shares of common stock, $0.01 par value, its only class of common stock.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive proxy statement for the 2025 Annual Meeting of Stockholders are incorporated by reference into Part III of this report.

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TABLE OF CONTENTS

|  | Page No.
| PART I |
ITEM 1. | Business | 3
ITEM 1A. | Risk Factors | 12
ITEM 1B. | Unresolved Staff Comments | 29
ITEM 1C. | Cybersecurity | 29
ITEM 2. | Properties | 30
ITEM 3. | Legal Proceedings | 31
ITEM 4. | Mine Safety Disclosures | 31
| PART II |
ITEM 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities | 32
ITEM 6. | RESERVED | 33
ITEM 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 34
ITEM 7A. | Quantitative and Qualitative Disclosures About Market Risk | 50
ITEM 8. | Financial Statements and Supplementary Data | 50
ITEM 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | 50
ITEM 9A. | Controls and Procedures | 50
ITEM 9B. | Other Information | 51
ITEM 9C. | Disclosure Regarding Foreign Jurisdictions That Prevent Inspections | 51
| PART III |
ITEM 10. | Directors, Executive Officers and Corporate Governance | 52
ITEM 11. | Executive Compensation | 52
ITEM 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | 52
ITEM 13. | Certain Relationships and Related Transactions, and Director Independence | 52
ITEM 14. | Principal Accounting Fees and Services | 52
| PART IV |
ITEM 15. | Exhibits and Financial Statement Schedule | 53
ITEM 16. | Form 10-K Summary | 57
| SIGNATURES | S-2

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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K (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 under “Risk Factors” contained in Item 1A of this Report and 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;
•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 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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PART I
Item 1. Business
Available Information
This Report, along with our Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, are available free of charge through our internet website (www.patenergy.com) as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. The information contained on our website is not part of this Report or other filings that we make with the SEC. The SEC maintains an internet site (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.
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.
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. The high density of our operations in the basins in which we are most active provides us the opportunity to leverage our fixed costs and to quickly respond with what we believe are highly efficient, integrated solutions that are best suited to address customer requirements.
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.
Other
Other consists of our oilfield rentals business, with a fleet of premium oilfield rental tools, along with the results of our ownership, as a non-operating working interest owner, in oil and natural gas assets located in Texas and New Mexico.
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Recent Developments
Recent Developments in Market Conditions — Quarterly average oil prices and our quarterly average number of rigs operating in the United States for 2022, 2023 and 2024 are as follows:

| 1 st Quarter |  | 2 nd Quarter |  | 3 rd Quarter |  | 4 th Quarter
2022 |  |  |  |  |  |  |
Average oil price per Bbl (1) | $ | 94.45 |  |  | $ | 108.72 |  |  | $ | 93.18 |  |  | $ | 82.79 |
Average rigs operating per day – U.S. (2) | 115 |  | 121 |  | 128 |  | 131
2023 |  |  |  |  |  |  |
Average oil price per Bbl (1) | $ | 75.93 |  |  | $ | 73.54 |  |  | $ | 82.25 |  |  | $ | 78.53 |
Average rigs operating per day – U.S. (2) | 131 |  | 128 |  | 120 |  | 118
2024 |  |  |  |  |  |  |
Average oil price per Bbl (1) | $ | 77.50 |  |  | $ | 81.81 |  |  | $ | 76.43 |  |  | $ | 70.73 |
Average rigs operating per day – U.S. (2) | 121 |  | 114 |  | 107 |  | 105 |

(1)The average oil price represents the average monthly West Texas Intermediate (WTI) spot price as reported by the United States Energy Information Administration.
(2)A rig is considered to be operating if it is earning revenue pursuant to a contract on a given day.
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 have been relatively range-bound since the end of 2022. The current demand for equipment and services remains impacted by macro conditions, including commodity prices, geopolitical environment, 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. Oil prices averaged $70.73 per barrel in the fourth quarter of 2024 and closed at $73.52 per barrel on February 3, 2025. Natural gas prices (based on the Henry Hub Spot Market Price) averaged $2.45 per MMBtu in the fourth quarter of 2024 and closed at $3.30 per MMBtu on February 3, 2025.
In our drilling services segment, our average active rig count in the United States for the fourth quarter of 2024 was 105 rigs. This was a decrease from our average active rig count for the third quarter of 2024 of 107 rigs. Our active rig count in the United States at December 31, 2024 of 103 rigs was less than the rig count of 121 rigs at December 31, 2023, reflecting the industry-wide activity declines due to increased drilling efficiencies and market consolidation. We expect our rig count in the United States will average 106 rigs in the first quarter of 2025. Term contracts help support our operating rig count. Based on contracts in place in the United States as of February 5, 2025, we expect an average of 64 rigs operating under term contracts during the first quarter of 2025 and an average of 40 rigs operating under term contracts during 2025.
During the fourth quarter of 2024, our completion services segment was impacted by several long-term dedicated customers reducing sequential completion activity after meeting their annual production targets. We expect a seasonal uptick in activity during the first quarter as customer budgets reset with the start of the new year.
Activity in our drilling products segment was relatively steady in 2024 compared to the prior year. Drilling products demand is expected to remain steady through the first quarter, given the expectation for a steady U.S. market and continued growth in international markets.
Our 2025 capital expenditure forecast is approximately $600 million.
Recent Developments in Joint Ventures, Business Combinations and Financial Matters — In December 2024, one of our subsidiaries closed a previously announced joint venture with subsidiaries of ADNOC Drilling and SLB. Our subsidiary holds a 15 percent interest in a newly created company named Turnwell Industries, which has been awarded a contract to drill and complete 144 unconventional wells for ADNOC. In exchange for the minority equity interest, we are providing unconventional drilling and completion expertise to Turnwell, as well as a limited cash contribution to fund our portion of initial working capital.
On September 1, 2023, we completed our merger (the “NexTier merger”) with NexTier Oilfield Solutions Inc. (“NexTier”), a predominately U.S. land-focused oilfield service provider, with a diverse set of well completion and production services across a variety of active basins Each share of common stock of NexTier issued and outstanding immediately prior to the effective time (including outstanding restricted shares) was converted into the right to receive 0.752 shares of our common stock, which based on the
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closing price of our common stock of $14.91 on September 1, 2023, valued the transaction at approximately $2.8 billion, including the assumption of debt.
On August 14, 2023, we completed our acquisition (the “Ulterra acquisition”) of Ulterra Drilling Technologies, L.P. (“Ulterra”), a global provider of specialized drill bit solutions. Total consideration for the acquisition included the issuance of 34.9 million shares of our common stock and payment of approximately $373 million of cash (after purchase price adjustments), which based on the closing price of our common stock of $14.94 on August 14, 2023, valued the transaction at closing at approximately $894 million.
On September 13, 2023, we completed the offering of $400 million in aggregate principal amount of 7.15% Senior Notes due 2033 (the “2033 Notes”). The net proceeds before offering expenses were approximately $396 million, which we used to repay amounts outstanding under our Prior Credit Agreement (as defined below).
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” included in Part II, Item 7— “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Report.
As of December 31, 2024, we had no borrowings outstanding under our Prior Credit Agreement. We had $2.1 million in letters of credit outstanding under the Prior Credit Agreement at December 31, 2024 and, as a result, had available borrowing capacity of approximately $613 million under the Prior Credit Agreement at that date.
Industry Segments
Our revenues, operating income and loss and identifiable assets are primarily attributable to three industry segments:
•drilling services,
•completion services, and
•drilling products.
Drilling Services Operations
General — We provide our contract drilling services to oil and natural gas operators in the United States, Colombia and Ecuador. As of December 31, 2024, we had 152 marketed land-based drilling rigs based in the following regions:

Region |  | Number of Rigs
West Texas |  | 70
Appalachia |  | 21
Oklahoma |  | 16
Rockies |  | 15
South Texas |  | 11
East Texas |  | 11
Colombia |  | 7
Ecuador |  | 1
Total |  | 152

All of these drilling rigs are electric rigs. An electric rig converts the power from its diesel or natural gas engines into electricity to power the rig. 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
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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 December 31, 2024, we had 135 Tier-1, super-spec rigs.
We also have a substantial inventory of drill pipe and drilling rig components, which may be used in the activation of additional drilling rigs or as upgrades or replacement parts for marketed rigs.
Drilling rigs are typically equipped with engines, drawworks, top drives, masts, pumps to circulate the drilling fluid, blowout preventers, drill pipe and other related equipment. Over time, components on a drilling rig are replaced or rebuilt. We invest significant funds each year as part of a program to modify, upgrade and maintain our drilling rigs. 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. Over the years, we have made performance and safety improvements to our rig fleet. Our APEX® rigs are AC-powered electric rigs with high pressure mud systems, walking systems and increased hookload capacity. During fiscal years 2024, 2023 and 2022, we spent approximately $265 million, $335 million, and $272 million, respectively, on capital expenditures in our Drilling Services operations.
Depth and complexity of the well, drill site conditions and the number of wells to be drilled on a pad are the principal factors in determining the specifications of the rig selected for a particular job.
Our contract drilling operations depend on the availability of drill pipe, replacement parts and other related rig equipment, fuel and other materials and qualified personnel. Some of these have been in short supply from time to time.
We perform repair and/or upgrade work to our drilling rig equipment at our yard facilities located in Texas, Oklahoma, Wyoming, Colorado, North Dakota, Ohio, Pennsylvania, and internationally in Colombia.
Drilling Contracts — Most of our drilling contracts are with established customers on a competitive bid or negotiated basis. Our bid for each job depends upon location, equipment to be used, estimated risks involved, estimated duration of the job, availability of drilling rigs and other factors particular to each proposed contract. Our drilling contracts are generally either on a well-to-well basis or a term basis. Well-to-well contracts are generally short-term in nature and cover the drilling of a single well or a series of wells. Term contracts are entered into for a specified period of time (we define term contracts as contracts with a duration of six months or more) or for a specified number of wells.
Our drilling contracts obligate us to provide and operate a drilling rig and to pay certain operating expenses, including wages of our drilling personnel and necessary maintenance expenses. Most drilling contracts are subject to termination by the customer on short notice and may or may not contain provisions for an early termination payment to us in the event that the contract is terminated by the customer.
Our drilling contracts provide for payment on a daywork basis, pursuant to which we provide the drilling rig and crew to the customer. The customer provides the program for the drilling of the well. Our compensation is based on a contracted rate per day during the period the drilling rig is utilized. We often receive a lower rate when the drilling rig is moving or when drilling operations are interrupted or restricted by adverse weather conditions or other conditions beyond our control. Daywork contracts typically provide separately for mobilization of the drilling rig.
Contract Drilling Activity — Information regarding our contract drilling activity for the last three years follows:

| Year Ended December 31,
| 2024 |  | 2023 |  | 2022
Average rigs operating per day – U.S. (1) | 112 |  |  | 124 |  | 124
Number of wells drilled during the year – U.S. | 2,376 |  |  | 2,530 |  | 2,489
Number of operating days – U.S. | 40,899 |  |  | 45,270 |  | 45,216

(1)A rig is considered to be operating if it is earning revenue pursuant to a contract on a given day.
Rig Fleet Evaluation — On a periodic basis, we evaluate our fleet of drilling rigs for marketability based on the condition of inactive rigs, expenditures that would be necessary to bring inactive rigs to working condition and the expected demand for drilling services by rig type. The components comprising rigs that will no longer be marketed are evaluated, and those components with continuing utility to our other marketed rigs are transferred to other rigs or to our yards to be used as spare equipment. The remaining components of these rigs are retired. During the third quarter of 2024, we identified 42 legacy, non-Tier-1 super-spec drilling rigs and related equipment to be abandoned. Based on the strong customer preference across the industry for Tier-1 super-spec drilling rigs, in addition to efficiency gains and technology advancements that have reduced the total number of rigs needed for the U.S. drilling
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market, we believe the 42 rigs that were abandoned had limited commercial opportunity. Accordingly, we recorded a charge of $114 million related to this abandonment during the third quarter of 2024. No similar charges were incurred in 2022 or 2023.
Drilling Technology — We continue to enhance the technology offerings that can be used with our drilling operations. Our proprietary operating system for APEX® drilling rigs, Cortex®, can allow for the deployment of custom applications for rig performance, control and optimization. For instance, our GenAssist® application can employ smart engine logic turning engines on and off to reduce fuel consumption and emissions. Our Cortex® Key edge server can connect to various systems at the well site, streaming large data sets and providing a single, high-speed data aggregation source. Our EcoCell® lithium battery hybrid energy management system is capable of utilizing stored energy to help reduce fuel consumption and emissions.
Directional Drilling — We generally utilize our own proprietary downhole motors and equipment to provide a comprehensive suite of directional drilling services, including directional drilling, measurement-while-drilling (“MWD”) and supply and rental of downhole performance motors, such as our Mpact® drilling motors, and MWD equipment, such as our Mpower™ MWD systems. Our customers primarily consist of oil and natural gas operators in the United States.
Wellbore Placement Optimization Services — We provide software and services used to improve the accuracy of directional and horizontal wellbores, wellbore quality, and on-bottom ROP (rate of penetration). Our MWD Survey FDIR (fault detection, isolation and recovery) service is a data analytics technology to analyze MWD survey data in real-time and more accurately identify the position of a well. Our HiFi Nav™ offering enhances FDIR by targeting improved vertical placement of the directional well within the reservoir. Our HiFi Guidance™ service utilizes trajectory optimization to determine optimal steering recommendations and placement within the reservoir, targeting minimal sliding, faster ROP, and a higher percentage of the wellbore placed in the desired drilling window. We provide these services to customers with onshore and offshore operations.
Other Drilling Services — We 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.
Completion Services Operations
Our 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. The high density of our operations in the basins in which we are most active provides us the opportunity to leverage our fixed costs and to quickly respond with what we believe are highly efficient, integrated solutions that are best suited to address customer requirements. Our completion services are designed in partnership with our customers to enhance both initial production rates and estimated ultimate recovery from new and existing wells.
We utilize our in-house capabilities, including our data control instruments business, to offer a technologically advanced and efficiency focused range of completion techniques. The majority of revenue for this segment is generated by our hydraulic fracturing business.
Hydraulic Fracturing — Hydraulic fracturing services are performed to enhance production of oil and natural gas from formations with low permeability and restricted flow of hydrocarbons. The process of hydraulic fracturing involves pumping a highly viscous, pressurized fracturing fluid, typically a mixture of water, chemicals and proppant, into a well casing or tubing in order to fracture underground mineral formations. These fractures release trapped hydrocarbon particles and free a channel for the oil or natural gas to flow freely to the wellbore for collection. Fracturing fluid mixtures include proppant that becomes lodged in the cracks created by the hydraulic fracturing process, “propping” them open to facilitate the flow of hydrocarbons upward through the well. To address evolving customer preferences for emissions-reducing equipment, we have invested in natural gas-powered equipment, including our 100% natural gas-powered Emerald™ line of hydraulic fracturing equipment.
Completion Support Services — Our Power Solutions business is an integrated natural gas treatment and delivery solution, which focuses on gas sourcing, compression, transport, decompression, treatment and related services for oilfield service operations. We believe this integration solution assists our customers by reducing emissions at the wellsite and throughout their operations. As part of our wellsite integration strategy to provide and integrate a variety of services for our customers at the wellsite to maximize efficiencies and profitability, in 2022, we acquired sand hauling, wellsite storage, and last mile logistics assets. The assets acquired were combined with our existing last mile logistics assets to create a leading player in the delivery and storage of proppant at the wellsite.
Wireline and Pumping Services — Our wireline services involve the use of a truck equipped with a spool of wireline that is unwound and lowered into oil and natural gas wells to convey specialized tools or equipment for well completion, well intervention, pipe recovery and reservoir evaluation purposes. We offer our wireline services in conjunction with our hydraulic fracturing services
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in “plug-and-perf” well completion to maximize efficiency for our customers. “Plug-and-perf” is a multi-stage well completion technique for cased-hole wells that consists of pumping a plug and perforating guns to a specified depth. Once the plug is set, the zone is perforated and the tools are removed from the well, a ball is pumped down to isolate the zones below the plug and the hydraulic fracturing treatment is applied. In addition, we offer wireline and pumping services that are not integrated with our fracturing services. We are one of the leading providers of perforating, pumpdown, pipe recovery, pressure pumping, and wellsite make-up and pressure testing services. We are highly experienced in safely servicing deep, high-pressure, high-temperature wells in some of the most active onshore basins in the United States. Our in-house manufacturing capabilities allow us to manage costs and lead times with regard to hardware and perforating guns, switches and accessories, providing us with a competitive advantage and enabling higher returns.
Cementing — Our cementing services incorporate custom engineered mixing and blending equipment that is designed to deliver precision and accuracy in providing annulus isolation and hydraulic seal, while protecting freshwater zones from our customers’ zone of interest. Our cement division has the expertise to cement shallow to complex high temperature, high pressure wells. We also offer engineering software and technical guidance for remedial cementing applications and acidizing to optimize the performance of our customers’ wells. We are one of the largest providers of specialty cementing services in the United States. Our operations are supported by multiple full-service laboratory facilities with advanced capabilities.
Completion Service Contracts — Our completion services operations are conducted pursuant to a work order for a specific job or pursuant to a contract generally for a specified period of time, which may include minimum revenue, usage or stage requirements. We are compensated based on a combination of charges for equipment, personnel, materials, mobilization and other items.
Equipment — We have well completion equipment used in providing hydraulic fracturing services as well as cementing and acid pumping services. We periodically evaluate our completion services assets for marketability based on the condition of inactive equipment, expenditures that would be necessary to bring the equipment to working condition and the expected demand for such equipment. The components of equipment that will no longer be marketed are evaluated, and those components with continuing utility will be used as parts to support active equipment. The remaining components of this equipment are retired.
Materials — Our completion services operations require the use of acids, chemicals, proppants, fluid supplies and other materials, any of which can be in short supply, including severe shortages, from time to time, and can be subject to significant price volatility. We purchase these materials from various suppliers. These purchases are made in the spot market or pursuant to other arrangements that may or may not cover all of our required supply. These supply arrangements sometimes require us to purchase the supply or pay liquidated damages if we do not purchase the material. Given the limited number of suppliers of certain of our materials, we may not always be able to make alternative arrangements if we are unable to reach an agreement with a supplier for delivery of any particular material or should one of our suppliers, including trucking companies, fail to timely deliver our materials.
Drilling Products Operations
Our Ulterra business has manufacturing and distribution sites of drilling equipment in North America and internationally, which are geographically positioned to serve the energy and mining markets in over 30 countries. Ulterra’s drilling equipment is used in oil and natural gas exploration and production and in mining operations. Ulterra has manufacturing and repair facilities located in Fort Worth, Texas, Leduc, Alberta and Saudi Arabia and repair facilities located in Argentina, Colombia and Oman.
Ulterra’s primary business is the design, manufacture, sale and rental of matrix and steel-bodied polycrystalline diamond compact (“PDC”) drill bits. PDC drill bits are typically rented, except in select international markets where they are sold. Used bits may be repaired and refurbished for the subsequent customer. Ulterra has an industry-leading position in the North American PDC drill bit market.
We periodically evaluate our drill bits for marketability based on the condition of inactive equipment, expenditures that would be necessary to bring the equipment to working condition and the expected demand for such equipment. The components of equipment that will no longer be marketed are evaluated, and those components with continuing utility will be used as parts to support active equipment. The remaining components of this equipment are retired. We had no impairment related to the marketability of our equipment during 2024.
Other Operations
Our oilfield rentals business has a fleet of premium rental tools and equipment and provides specialized services for land-based oil and natural gas drilling, completion and workover activities in many of the major producing oil and natural gas basins in the United States. In addition, we own and invest, as a non-operating working interest owner, in oil and natural gas assets that are primarily located in Texas and New Mexico.
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Research, Engineering and Technology
We employ research, engineering and technology teams across our businesses, who work on initiatives to enhance our existing product and service offerings and develop new products and services to meet customer demands.
Contracts
We believe that our contracts for drilling services, completion services, drilling products and other services and products generally provide for indemnification rights and obligations that are customary for the markets in which we conduct those operations. However, each contract contains the actual terms setting forth our rights and obligations and those of the customer or supplier, any of which rights and obligations may deviate from what is customary due to particular industry conditions, customer or supplier requirements, applicable law or other factors.
Customers
Our customer base includes major, independent and other oil and natural gas operators. With respect to our consolidated operating revenues in 2024, we received approximately 53% from our ten largest customers and approximately 38% from our five largest customers. During 2024, one customer accounted for approximately $605 million, or approximately 11%, of our consolidated operating revenues. The loss of, or reduction in business from, one or more of our larger customers could have a material adverse effect on our business, financial condition, cash flows and results of operations.
Backlog
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 December 31, 2024 and 2023 was approximately $426 million and $700 million, respectively. Approximately 7.1% of our contract drilling backlog in the United States at December 31, 2024 is reasonably expected to remain after 2025. See Note 3 of Notes to consolidated financial statements in Item 8 of this Report and “Item 1A. Risk Factors – 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” for information pertaining to backlog.
Competition
The businesses in which we operate are highly competitive. Historically, available equipment used in our drilling services and completion services businesses has frequently exceeded demand, particularly in an industry downturn. The price for our services is a key competitive factor, in part because equipment used in these businesses can be moved from one area to another in response to market conditions. In addition to price, we believe availability, condition and technical specifications of equipment (including emission reduction capabilities), quality of personnel, service quality and safety record are key factors in determining which contractor is awarded a job. We expect that the market for our services will continue to be highly competitive.
Human Capital and Sustainability
We strive to be a leader in our industry in the area of environmental, social, governance and other sustainability-related issues, and we remain committed to managing these issues for the long-term benefit of our employees, our communities and our business. We aim to minimize our environmental impact in the communities in which we work and live, while providing services for our customers in a safe and responsible manner. We invest extensively in the safety, health and well-being of our people, who, through the diversity of their backgrounds, experiences and talents, are our greatest strength. Importantly, we maintain a rigorous focus on ethics and integrity at every level of our operations, values which are embedded in our culture and a practice on which all of our success depends.
Environment – We continue to pursue initiatives to mitigate climate change risk and make improvements in air quality, water quality, land usage, use of energy and reducing waste materials. For example, we utilize natural gas engines, dual-fuel equipment and other technologies that reduce our carbon and other greenhouse gas emissions as compared to our traditional diesel-only equipment, and we employ spill prevention plans and use additional protective measures in environmentally sensitive areas.
We have strengthened our position as a leader in alternative fuel technology with the commercialization of our EcoCell® lithium battery hybrid energy management system. The EcoCell® system is capable of efficiently displacing one of the gensets on a drilling rig to reduce both fuel consumption and emissions. The value of this technology is enhanced when used in combination with our Cortex® power management system and our dual-fuel engines, as the natural gas substitution rate can be optimized.
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Through our Current Power business, we provide in-house electrical engineering, control system automation and installation services to connect drilling rigs to utility electrical lines. This capability enables our customers to use utility power, instead of natural gas or diesel fuel, to power drilling operations. Using utility power is an optimal power solution for our drilling rigs as it minimizes emission impacts at the wellsite.
Some of our key human capital areas of focus include:
Employees – We had approximately 9,200 full-time employees as of January 31, 2025. The number of employees fluctuates depending on the current and expected demand for our services. We consider our employee relations to be satisfactory. None of our U.S. employees are represented by a union. Although some of our Colombian employees may be union members, we have not entered into any collective bargaining arrangements with the unions with which those employees are affiliated.
Training and Safety – Our training programs include opportunities for employees to advance in their professional careers through intensive, multi-day classroom training programs in numerous skills and competencies, as well as management training programs. These programs are geared to providing our employees with opportunities to advance throughout our company.
The safety of our employees and others is our highest priority, as our goal is to provide an incident-free work environment. We have robust safety training programs that are designed to comply with applicable laws and industry standards and to benefit our employees, communities and our business. All U.S. field-based employees are required to have annual safety education that incorporates learning associated with hazard awareness, safe systems of work, permission to work, stop work authority, energy isolation, material handling and management of change.
Diversity, Inclusion and Respect – We are committed to fostering a work environment where all people feel valued and respected. We embrace our diversity of people, thoughts and talents, and combine these strengths to pursue extraordinary results for our company, our employees and our stockholders. We are committed to recruiting, hiring and retaining the highest caliber talent for our business by utilizing outreach initiatives and partnerships with a diverse group of organizations, industry associations and networks.
All employees are educated annually on our commitment to a respectful workplace for all to ensure they understand their role as they engage with co-workers.
Maintaining our Core Values – We provide annual training for our employees on our Code of Business Conduct and Ethics, which addresses conflicts of interest, confidentiality, fair dealing with others, proper use of company assets, compliance with laws, insider trading, keeping of books and records, zero tolerance for discrimination and harassment in the work environment, as well as reporting of violations.
Health and Benefits – Our health and benefits program provides for extensive preventative care and is designed to improve our employees’ fitness for work, personal safety on the job and overall well-being. We have implemented policies allowing many of our office-based employees the flexibility to work from home.
Government and Environmental Regulation
Our operations and facilities are subject to numerous federal, state, foreign, regional and local laws, rules and regulations related to various aspects of our business and the oil and natural gas industry including:
•drilling of oil and natural gas wells,
•hydraulic fracturing, wireline and pumping, completion support and cementing,
•provision of specialized drill bit solutions,
•directional drilling services,
•services that improve the accuracy of directional and horizontal wellbores, including for customers with offshore operations, wellbore quality, and on-bottom ROP,
•containment and disposal of hazardous materials, oilfield waste, other waste materials and acids,
•use of underground storage tanks and injection wells,
•servicing of equipment for drilling contractors,
•provision of electrical controls and automation,
•conducting international operations, and
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•our employees.
Our business operations are subject to various environmental, as well as employee health and safety, laws and regulations, including those addressing the management, disposal and releases of regulated substances. For more information, please refer to our discussion under “Item 1A. Risk Factors – Environmental and occupational health and safety laws and regulations, including violations thereof, could materially adversely affect our operating results.”
Our activities include the performance of hydraulic fracturing services to enhance the production of oil and natural gas from formations with low permeability, such as shale and other unconventional formations. See “Item 1A. Risk Factors – The adoption of any future federal, state, or local laws or implementing regulations imposing reporting obligations on, or limiting or banning, the hydraulic fracturing process could make it more difficult to complete natural gas and oil wells and could have a material adverse effect on our business, results of operations, and financial condition.”
There has been an increasing focus of local, state, national and international regulatory bodies on greenhouse gas (“GHG”) emissions and climate change issues. Several states and geographic regions in the United States, as well as foreign jurisdictions, have adopted legislation and regulations to reduce emissions of GHGs, including cap and trade regimes and commitments to contribute to meeting the goals of international treaties related to GHG emissions. See “Item 1A. Risk Factors – Our and our customers’ operations are subject to a number of risks arising out of the threat of climate change that could result in increased operating and capital costs, limit the areas in which oil and natural gas production may occur and reduce demand for our services.”
We operate throughout North America and internationally in over 30 countries and, accordingly, are subject to the U.S. Foreign Corrupt Practices Act (“FCPA”) and similar anti-bribery and anti-corruption laws in other jurisdictions. Our operations also are subject to other laws and regulations in relation to our international operations, including with respect to the import and export of certain goods and economic sanctions. See “Item 1A. Risk Factors – Political, economic and social instability risk and laws associated with conducting international operations could adversely affect our opportunities and future business.”
The adoption of laws, rules and regulations affecting the oil and natural gas industry for economic, environmental and other policy reasons could increase costs relating to drilling, completion and production, delay the permitting of, or related to, such operations, restrict or prohibit oil and natural gas development in certain areas, reduce the demand for oil and natural gas and otherwise have an adverse effect on our operations or business, and could have a material adverse effect on our business, financial condition, cash flows and results of operations. To date, applicable environmental and other laws and regulations in the places in which we operate have not required the expenditure of significant resources outside the ordinary course of business. We do not anticipate any material capital expenditures for environmental control facilities or extraordinary expenditures to comply with environmental rules and regulations in the foreseeable future. However, compliance costs under existing laws or under any new requirements could become material, and we could incur liability in any instance of noncompliance.
Risks and Insurance
We have indemnification agreements with many of our customers, and we also maintain liability and other forms of insurance. In general, our contracts typically contain provisions requiring our customers to indemnify us for, among other things, reservoir and certain pollution damage.
In addition, we maintain insurance coverage of the types and in the amounts we believe to be customary in the industry, but we do not insure against all risks, either because insurance is not available or because it is not commercially justifiable. The insurances that we maintain include coverage for fire, windstorm and other risks of physical loss to our equipment and certain other assets, employers’ liability, automobile liability, commercial general liability, workers’ compensation as well as insurance for other specific risks, together with excess loss liability insurance coverage. We have also elected to retain a greater amount of risk through increased deductibles as compared to prior years, or self-insurance on certain insurance policies. We cannot assure that any insurance obtained by us will be adequate to cover any losses or liabilities nor can we assure that any insurance obtained by us will continue to be made available for purchase or made available on acceptable terms. While we carry insurance to cover physical damage to, or loss of, a substantial portion of our equipment and certain other assets, such insurance does not cover the full replacement cost of such equipment or other assets, and in certain cases, such as losses arising from or attributable to fire and/or explosion resulting from our hydraulic fracturing operations at the wellsite, is subject to significantly higher deductibles than are applicable to our other coverages. We also self-insure a number of risks, including loss of earnings and business interruption and most of our cybersecurity risks, and we do not carry a significant amount of insurance to cover risks of underground reservoir damage.
If a significant accident or other event occurs that is not fully covered by insurance or an enforceable and recoverable indemnity from a third party, it could have a material adverse effect on our business, financial condition, cash flows and results of operations. See “Item 1A. Risk Factors – Our operations are subject to a number of operational risks, including environmental and weather risks,
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which could expose us to significant losses and damage claims. We are not fully insured against all of these risks and our contractual indemnity provisions may not fully protect us.”
Seasonality
Seasonality has not significantly affected our overall operations. Toward the end of calendar years, we experience slower activity in connection with the holidays and as customers’ capital expenditure budgets are depleted and/or their annual drilling and completion targets have been met. Occasionally, our operations are negatively impacted by severe weather conditions.
Raw Materials and Subcontractors
We use many suppliers of raw materials and services. Although these materials and services have historically been available, there is no assurance that such materials and services will continue to be available on favorable terms or at all. We also utilize numerous independent subcontractors from various trades.
Item 1A. Risk Factors.
You should consider each of the following factors as well as the other information in this Report in evaluating our business and our prospects. Additional risks and uncertainties not presently known to us or that we currently consider immaterial may also impair our business operations. If any of the following risks actually occur, our business, financial condition, cash flows and results of operations could be harmed. You should also refer to the other information set forth in this Report, including our consolidated financial statements and the related notes.
Risk Factors Summary
The following is a summary of the principal risks included in this Report that we believe could adversely affect our business, financial condition, cash flows and results of operations:
Business and Operating Risks
•We are dependent on the oil and natural gas industry and market prices for oil and natural gas. Declines in customers’ operating and capital expenditures and in oil and natural gas prices may adversely affect our operating results.
•Global economic conditions may adversely affect our operating results.
•A surplus of equipment and a highly competitive oil service industry may adversely affect our utilization and profit margins and the carrying value of our assets.
•Our operations are subject to a number of operational risks, including environmental and weather risks, which could expose us to significant losses and damage claims. We are not fully insured against all of these risks and our contractual indemnity provisions may not fully protect us.
•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.
•New technologies may cause our operating methods, equipment, products and services to become less competitive, and higher levels of capital expenditures may be necessary to remain competitive.
•Loss of key personnel and competition for experienced personnel may negatively impact our financial condition and results of operations.
•The loss or consolidation of key customers could have a material adverse effect on our financial condition and results of operations.
•Shortages, delays in delivery, and interruptions in supply, of equipment and materials could adversely affect our operating results.
•Our business is subject to cybersecurity risks and threats.
•Our commitments under supply agreements could exceed our requirements, exposing us to risks including price, timing of delivery and quality of equipment and materials upon which our business relies.
•Growth through acquisitions, the building or upgrading of equipment and the development of technology is not assured.
•Complications with the design or implementation of our new enterprise resource planning system could adversely impact our business and operations.
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•Fuel conservation measures, alternative fuel requirements and increasing consumer demand for alternatives to oil and natural gas could reduce demand for oil and natural gas, which would, in turn, reduce the demand for our services.
Legal and Regulatory Risks
•The adoption of any future federal, state, or local laws or implementing regulations imposing reporting obligations on, or limiting or banning, the hydraulic fracturing process could make it more difficult to complete natural gas and oil wells and could have a material adverse effect on our business, results of operations, and financial condition.
•Our and our customers’ operations are subject to a number of risks arising out of the threat of climate change that could result in increased operating and capital costs, limit the areas in which oil and natural gas production may occur and reduce demand for our services.
•Environmental and occupational health and safety laws and regulations, including violations thereof, could materially adversely affect our operating results.
•Intellectual property disputes could negatively impact our operations, costs, revenues and competitiveness.
•The design, manufacture, sale or rental, and servicing of products, including drill bits and electrical controls, may subject us to liability for personal injury, property damage and environmental contamination.
•Legal proceedings and governmental investigations could have a negative impact on our business, financial condition and results of operations.
•Political, economic and social instability risk and laws associated with conducting international operations could adversely affect our opportunities and future business.
•We are subject to complex and evolving laws and regulations regarding data privacy and security.
Financial Risks
•Investor sentiment and public perception related to the oil and natural gas industry and to ESG initiatives could increase our costs of capital and our reporting requirements and impact our operations.
•Variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.
•Our ability to access capital markets could be limited, and a downgrade in our credit rating could negatively impact our cost of and ability to access capital.
•We may not be able to generate sufficient cash to service all of our debt and we may be forced to take other actions to satisfy our obligations under our debt, which may not be successful.
•Our return of capital to stockholders, including through the payment of dividends and repurchases of our common stock, is within the discretion of our Board of Directors, and there is no guarantee that we will return capital to shareholders, including through the payment of dividends and repurchases of our common stock, in the future or at levels anticipated by our stockholders.
•Our ability to utilize our historic U.S. net operating loss carryforwards is expected to be limited as a result of the completion of the NexTier merger.
Risks Related to Our Common Stock and Corporate Structure
•The market price of our common stock may be highly volatile, and investors may not be able to resell shares at or above the price paid.
•Anti-takeover measures in our charter documents and under state law could discourage an acquisition and thereby affect the related purchase price.
•Our bylaws provide that the Court of Chancery of the State of Delaware and the federal district courts of the United States are the exclusive forums for substantially all disputes between us and our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers or employees.
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Business and Operating Risks
We are dependent on the oil and natural gas industry and market prices for oil and natural gas. Declines in customers’ operating and capital expenditures and in oil and natural gas prices may adversely affect our operating results.
We depend on our customers’ willingness to make operating and capital expenditures to explore for, develop and produce oil and natural gas. When these expenditures decline, our business may suffer. Our customers’ willingness to explore, develop and produce depends largely upon prevailing industry conditions that are influenced by numerous factors over which we have no control, such as:
•the supply of and demand for oil and natural gas, including current natural gas storage capacity and usage,
•the prices, and expectations about future prices, of oil and natural gas,
•the supply of and demand for drilling services, completion services and drilling products,
•the cost of exploring for, developing, producing and delivering oil and natural gas,
•the availability of capital for oil and natural gas industry participants, including our customers, and the extent to which they are willing or able to deploy capital,
•the availability of and constraints in pipeline, storage and other transportation capacity in the basins in which we operate,
•the environmental, tax and other laws and governmental regulations regarding the exploration, development, production, use and delivery of oil and natural gas, and in particular, public pressure on, and legislative and regulatory interest within, federal, state, foreign, regional and local governments to stop, significantly limit or regulate drilling services and completion services activities, including hydraulic fracturing,
• increased focus by the investment and financing community and the general public on sustainability practices in the oil and natural gas industry, and
•merger and divestiture activity among oil and natural gas producers.
In particular, our revenues, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas and expectations about future prices. Oil and natural gas prices and markets can be extremely volatile. Prices, and expectations about future prices, are affected by factors such as:
•market supply and demand,
•the desire and ability of the Organization of Petroleum Exporting Countries (“OPEC”), its members and other oil-producing nations, such as Russia, to set and maintain production and price targets,
•the level of production by OPEC and non-OPEC countries,
•domestic and international military, political, economic, health and weather conditions, including the impacts of war, including the impact of the ongoing armed conflicts between Russia and Ukraine and in the Middle East and the continuation of, or any escalation in the severity of, these conflicts, or terrorist activity, pandemics and other unexpected disasters or events,
•changes to tax, tariff and import/export regulations and sanctions by the United States or other countries,
•legal and other limitations or restrictions on exportation and/or importation of oil and natural gas,
•technical advances affecting energy consumption and production, and
•the development, price, availability and market acceptance of alternative fuels and energy sources.
All of these factors are beyond our control. Commodity prices have historically been volatile, but have been relatively range-bound since the end of 2022. The current demand for equipment and services remains impacted by macro conditions, including commodity prices, geopolitical environment, 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. Oil prices averaged $70.73 per barrel in the fourth quarter of 2024 and closed at $73.52 per barrel on February 3, 2025. Natural gas prices (based on the Henry Hub Spot Market Price) averaged $2.45 per MMBtu in the fourth quarter of 2024 and closed at $3.30 per MMBtu on February 3, 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
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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.
Global economic conditions may adversely affect our operating results.
Concerns regarding global economic conditions, energy costs, geopolitical issues, supply chain disruptions, public health crises or global pandemics, inflation and the availability and cost of credit have contributed, and may in the future contribute, to increased economic uncertainty. Demand for energy and for oil and natural gas end products is highly sensitive to economic conditions; as a result, global economic conditions, indications that economic growth is slowing and volatility in commodity prices may cause our customers to reduce or curtail their drilling and well completion programs, which could result in a decrease in demand for our services. In addition, uncertainty in the capital markets, whether due to global economic conditions, low commodity prices or otherwise, may result in reduced access to, or an inability to obtain, financing by us, our customers and our suppliers and result in reduced demand for our services. An economic slowdown or recession in the United States or in any other country that significantly affects the supply of or demand for oil or natural gas could negatively impact our operations and therefore adversely affect our results. Furthermore, these factors may result in certain of our customers experiencing an inability or unwillingness to pay suppliers, including us. The global economic environment in the past has experienced significant deterioration in a relatively short period, such as a result of the COVID-19 pandemic or the ongoing armed conflicts between Russia and Ukraine and in the Middle East, and there is no assurance that the global economic environment, or expectations for the global economic environment, will not quickly deteriorate again due to one or more factors, including as a result of actual or perceived threats to geopolitical stability, changes in production from OPEC, its members and other oil-producing nations, or governmental actions or restrictions in response to events such as a global pandemic. A deterioration in the global economic environment could have a material adverse effect on our business, financial condition, cash flows and results of operations.
A surplus of equipment and a highly competitive oil service industry may adversely affect our utilization and profit margins and the carrying value of our assets.
Our industry is highly competitive, and available drilling services equipment, completion services equipment, and drilling products often exceeds the demand for such equipment and products. A low commodity price environment or capital spending reductions by our customers due to additional customer consolidation, investor requirements or other reasons can result in substantially more equipment and products being available than are needed to meet demand. Low commodity prices and a rise in new and upgraded equipment or products can result in excess capacity and substantial competition for a declining number of drilling services and completion services contracts and drilling products rentals and sales.
Operating costs for our drilling services and completion services businesses include all direct and indirect costs associated with the operation, maintenance and support of our equipment, which is often not affected by changes in our rates and utilization. During periods of reduced revenue and/or activity, certain of our fixed costs, such as depreciation, may not decline and often we may incur additional costs. During times of reduced utilization, reductions in costs may not be immediate as we may incur additional costs associated with maintaining and stacking equipment, or we may not be able to fully reduce the cost of our support operations in a particular geographic region due to the need to support the remaining operations in that region. Accordingly, a decline in revenue due to lower rates and/or utilization may not be offset by a corresponding decrease in operating costs, which could have a material adverse impact on our business, financial condition and results of operations.
Even in an environment of high oil and natural gas prices and/or increased drilling and completion activity, reactivation and improvement of existing drilling services and completion services equipment, construction of new technology drilling services and completion services equipment, movement of drilling services and completion services equipment from region to region in response to market conditions or otherwise can lead to a surplus of equipment.
In times of reduced demand for our industry’s services, certain of our industry competitors may initiate bankruptcy proceedings or engage in debt refinancing transactions, management changes, or other strategic initiatives in an attempt to reduce operating costs to maintain a position in the market. This could result in such competitors emerging with stronger or healthier balance sheets and, in turn, an improved ability to compete with us in the future. We may also see corporate consolidations among our customers, competitors and/or vendors, which could significantly alter industry conditions and competition within the industry, and have a material adverse effect on our business, financial condition, cash flows and results of operations.
We periodically seek to increase the prices on our services to offset rising costs, earn returns on our capital investment, and otherwise generate higher returns for our stockholders. However, we operate in a very competitive industry, and we are not always
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successful in raising or maintaining our existing prices. Even if we are able to increase our prices, we may not be able to do so at a rate that is sufficient to offset rising costs, including capital expenditures, without adversely affecting our activity levels. The inability to maintain our pricing and to increase our pricing as costs, including capital expenditures, increase could have a material adverse effect on our business, financial condition, cash flows and results of operations. In addition, we may be unable to replace fixed-term contracts that expire or are terminated early, extend expiring contracts or obtain new contracts in the spot market, and the rates and other material terms under any new or extended contracts may be on substantially less favorable rates and terms.
Accordingly, high competition and a surplus of equipment and products can cause oil and natural gas service contractors to have difficulty maintaining pricing, utilization and profit margins and, at times, result in operating losses. We cannot predict the future level of competition or surplus equipment and products in the oil and natural gas service businesses or the level of demand for our drilling services, completion services or drilling products.
A surplus of operable land drilling rigs, other drilling services equipment and drilling products, increasing rig specialization and surplus of completion services equipment, which can be exacerbated by capital spending reductions by our customers, could affect the fair market value of our drilling services equipment, completion services equipment, and drilling products, which in turn could result in additional impairments of our assets. A prolonged period of lower oil and natural gas prices or changes in customer preferences and requirements could result in future impairment to our long-lived assets. For example, we recognized impairment charges of $3.8 million, $7.0 million and $4.5 million in 2024, 2023 and 2022, respectively.
Our operations are subject to a number of operational risks, including environmental and weather risks, which could expose us to significant losses and damage claims. We are not fully insured against all of these risks and our contractual indemnity provisions may not fully protect us.
Our operations are subject to many hazards inherent in the businesses in which we operate, including inclement weather, blowouts, explosions, fires, loss of well control, motor vehicle accidents, equipment failure, unplanned power outages and surges, computer system disruptions or cybersecurity incidents, pollution, exposure and reservoir damage. These hazards could cause personal injury or death, work stoppage, and serious damage to equipment and other property, as well as significant environmental and reservoir damages. These risks could expose us to substantial liability for personal injury, wrongful death, property damage, loss of oil and natural gas production, pollution and other environmental damages, and consequential damages. An accident or other event resulting in significant environmental or property damage, or injuries or fatalities involving our employees or other persons could also trigger investigations by federal, state or local authorities. Such an accident or other event could cause us to incur substantial expenses in connection with the investigation, remediation and resolution, as well as cause lasting damage to our reputation, loss of customers and an inability to obtain insurance.
We have indemnification agreements with many of our customers, and we also maintain liability and other forms of insurance. In general, our contracts typically contain provisions requiring our customers to indemnify us for, among other things, reservoir and certain pollution damage. Our right to indemnification may, however, be unenforceable or limited due to negligent or willful acts or omissions by us, our subcontractors and/or suppliers. In addition, certain states, including Louisiana, New Mexico, Texas and Wyoming, have enacted statutes generally referred to as “oilfield anti-indemnity acts” expressly prohibiting certain indemnity agreements contained in or related to oilfield services agreements. Such oilfield anti-indemnity acts may restrict or void a party’s indemnification of us.
Our customers and other third parties may dispute, or be unable to meet, their indemnification obligations to us due to financial, legal or other reasons. Accordingly, we may be unable to transfer these risks to our customers and other third parties by contract or indemnification agreements. Incurring a liability for which we are not fully indemnified or insured could have a material adverse effect on our business, financial condition, cash flows and results of operations.
In addition, we maintain insurance coverage of the types and in the amounts we believe to be customary in the industry, but we do not insure against all risks, either because insurance is not available or because it is not commercially justifiable. See “Item 1. Business – Risks and Insurance” for a description of our insurance coverage. We also self-insure a number of risks, including loss of earnings and business interruption and most of our cybersecurity risks, and we do not carry a significant amount of insurance to cover risks of underground reservoir damage.
Our insurance may not in all situations provide sufficient funds to protect us from all liabilities that could result from our operations. Our coverage includes aggregate policy limits and exclusions. As a result, we retain the risk for any loss in excess of these limits or that is otherwise excluded from our coverage. There can be no assurance that insurance will be available to cover any or all of our operational or other risks, or, even if available, that insurance premiums or other costs will not rise significantly in the future, so as to make the cost of such insurance prohibitive, or that our coverage will cover a specific loss. Further, we may experience difficulties in collecting from insurers or such insurers may deny all or a portion of our claims for insurance coverage. Incurring a liability for
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which we are not fully insured or indemnified could materially adversely affect our business, financial condition, cash flows and results of operations.
If a significant accident or other event occurs that is not fully covered by insurance or an enforceable and recoverable indemnity from a third party, it could have a material adverse effect on our business, financial condition, cash flows and results of operations.
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.
Fixed-term drilling contracts customarily provide for termination at the election of the customer, with an early termination payment to us if a contract is terminated prior to the expiration of the fixed term. However, in certain circumstances, for example, destruction of a drilling rig that is not replaced within a specified period of time, our bankruptcy, or a breach of our contract obligations, the customer may not be obligated to make an early termination payment to us. Additionally, during depressed market conditions or otherwise, customers may be unable to satisfy their contractual obligations or may seek to terminate, suspend or renegotiate or otherwise fail to honor their contractual obligations, including as a result of their bankruptcy. In addition, we may not be able to perform under these contracts due to events beyond our control, and our customers may seek to terminate or renegotiate our contracts for various reasons, including those described above. As a result, we may be unable to realize all of our current contract drilling backlog. In addition, the termination, suspension or renegotiation of fixed-term contracts without the receipt of early termination payments could have a material adverse effect on our business, financial condition, cash flows and results of operations.
As of December 31, 2024, our contract drilling backlog in the United States for future revenues under term contracts, which we define as contracts with a duration of six months or more, was approximately $426 million. Please see Note 3 of Notes to consolidated financial statements in Item 8 of this Report for a description of our calculation of backlog. Our contract drilling backlog may decline, as fixed-term drilling contract coverage over time may not be offset by new contracts or may be reduced by price adjustments to existing contracts, including as a result of a decline in the price of oil and natural gas, capital spending reductions by our customers or other factors. For these and other reasons, our contract drilling backlog may not generate sufficient liquidity for us during periods of reduced demand for our services or otherwise.
New technologies may cause our operating methods, equipment, products and services to become less competitive, and higher levels of capital expenditures may be necessary to remain competitive.
The market for our services and products is characterized by continual technological and process developments that have resulted in, and will likely continue to result in, substantial improvements in the functionality and performance, including environmental performance, of drilling services equipment, completion services equipment, and drilling products. Our customers are increasingly demanding the services of newer, higher specification drilling rigs and completion services and other equipment, as well as new and improved technology, such as drilling automation technology and lower-emissions operations and services, specialized drill bit solutions and data analytics. Accordingly, we may have to allocate a higher proportion of our capital expenditures to maintain and improve existing rigs and completion services and other equipment, purchase and construct newer, higher specification drilling rigs and completion services and other equipment to meet the increasingly sophisticated needs of our customers, and develop new and improved technology, specialized drill bit solutions and data analytics. In addition, technological changes, process improvements and other factors that increase operational efficiencies could continue to result in oil and natural gas wells being drilled and completed more quickly, which could reduce the number of revenue earning days. Technological and process developments in the completion services and other drilling services businesses could have similar effects.
We continually attempt to develop or acquire new technologies for use in our business. For example, we have invested in natural gas-powered equipment, including electric, direct drive, and dual fuel pumps, to replace legacy diesel completion services equipment. In the event that we are successful in developing or acquiring new technologies for use in our business, there is no guarantee of future demand for those technologies. Customers may be reluctant or unwilling to adopt our new technologies. We may also have difficulty negotiating satisfactory terms for our new technologies, including terms that would enable us to obtain acceptable returns on our investment in the development or acquisition of new technologies.
Development and acquisition of new technology is critical to maintaining our competitiveness. There can be no assurance that we will be able to successfully develop or acquire technology that our customers demand. Some of our competitors have greater financial, technical and personnel resources that may allow them to enjoy technological advantages and develop, acquire and implement new technology on a more timely basis or in a more cost-effective manner. If we are not successful keeping pace with technological advances in a timely and cost-effective manner, demand for our services may decline. If any technology that we need to successfully compete is not available to us or that we implement in the future does not work as we expect, we may be adversely affected. Additionally, new technologies, services or standards could render some of our equipment, services and products obsolete, which could reduce our competitiveness and have a material adverse impact on our business, financial condition, cash flows and results of operation.
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Loss of key personnel and competition for experienced personnel may negatively impact our financial condition and results of operations.
We greatly depend on the efforts of our key employees to manage our operations. The loss of members of management could have a material adverse effect on our business. In addition, we utilize highly skilled field-based and non-field-based personnel in operating and supporting our businesses and in developing new technologies. In times of increasing demand for our services, it may be difficult to attract and retain qualified field-based and non-field-based personnel, particularly after a prolonged industry downturn. During periods of high demand for our services or inflation, wage rates for personnel are also likely to increase (and, during recent periods of high demand and inflation, have increased), resulting in higher operating costs. During periods of lower demand for our services, we may experience reductions in force and voluntary departures of personnel, which could adversely affect our business and make it more it difficult to meet customer demands when demand for our services improves. In addition, even in a period of generally lower demand for our services, if there is a high demand for our services in certain areas, it may be difficult to attract and retain qualified personnel to perform services in such areas. The loss of key employees, the failure to attract and retain qualified personnel and the increase in labor costs could have a material adverse effect on our business, financial condition, cash flows and results of operations.
The loss or consolidation of key customers could have a material adverse effect on our financial condition and results of operations.
Business consolidations within the oil and natural gas industry in recent years have resulted in some of our largest customers combining and using their size and purchasing power to seek economies of scale and pricing concessions. Continuing consolidation within the industry may result in reduced capital spending within the industry generally and by our customers specifically, all of which may lead to decreased demand for our products and services. There is no assurance that we will be able to maintain our level of business and profitability with a customer after its consolidation or replace that business and profit with other customers. Additionally, consolidation among our competitors could significantly alter industry conditions and competition within the industry. As a result, the acquisition of one or more of our key customers or consolidation among our competitors may have a significant adverse impact on our business, results of operations, financial condition and cash flows. We are unable to predict what effect further consolidation in the industry may have on capital spending by our customers, prices that we can charge, our selling strategies, our competitive position, our ability to retain customers or our ability to negotiate favorable agreements with our customers, and our revenue and profitability.
With respect to our consolidated operating revenues in 2024, we received approximately 53% from our ten largest customers, approximately 38% from our five largest customers and 11% from our largest customer. The loss of, or reduction in business from, one or more of our larger customers, due to consolidation or otherwise, could have a material adverse effect on our business, financial condition, cash flows and results of operations.
Shortages, delays in delivery, and interruptions in supply, of equipment and materials could adversely affect our operating results.
Periodically, the oilfield services industry has experienced shortages of equipment for upgrades, drill pipe, raw materials, replacement parts and other equipment and materials, including, in the case of our completion services operations, proppants, cement, acid, gel and water. These shortages can cause the price of these items to increase significantly and require that orders for the items be placed well in advance of expected use. In addition, any interruption in supply could result in significant delays in delivery of equipment and materials or prevent operations. Interruptions may be caused by, among other reasons:
•weather issues, whether short-term such as a hurricane, or long-term such as a drought,
•labor shortages or other labor issues,
•transportation, fuel shortages and other logistical challenges, and
•a shortage in the number of vendors able or willing to provide the necessary equipment and materials, including as a result of commitments of vendors to other customers or third parties or bankruptcies or consolidation.
These price increases, delays in delivery and interruptions in supply may require us to delay operations, increase capital and repair expenditures or otherwise incur higher operating costs. During recent years, there have been significant disruptions and delays across the global supply chain, which have created a tightening of supplies and shortages in a number of areas, including basic raw materials. Severe shortages, delays in delivery and interruptions in supply could increase our costs and limit our ability to construct, operate, maintain and upgrade drilling services equipment, completion services equipment, drilling products and other equipment and could have a material adverse effect on our business, financial condition, cash flows and results of operations.
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Our business is subject to cybersecurity risks and threats.
Our operations are increasingly dependent on effective and secure information technologies and services, including our own systems and the systems of third party vendors and service providers upon which we rely, such as those providing cloud services to us. Threats to information technology systems associated with cybersecurity risks and cyber incidents or attacks continue to grow, and include, among other things, storms and natural disasters, terrorist attacks, utility outages, attempts to gain unauthorized access to data and systems, theft, viruses, malware, ransomware, denial-of-service attacks, design defects, human error, or complications encountered as existing systems are maintained, repaired, replaced, or upgraded. Risks associated with these threats include, among other things:
•theft or misappropriation of funds, including via “phishing” or similar attacks directed at us or third parties, including our customers and vendors;
•loss, corruption, or misappropriation of intellectual property, or other proprietary or confidential information (including customer, supplier, or employee data);
•disruption or impairment of our and our customers’ and vendors’ business operations and safety procedures;
•personal injuries and destruction or damage to property;
•downtime and loss of revenue;
•injury to our reputation, including the perception of our products or services as having security vulnerabilities;
•negative impacts on our ability to compete;
•loss or damage to our and our customers’ and vendors’ information technology systems, including operational technologies and worksite data delivery systems;
•exposure to litigation and legal and regulatory liability and costs; and
•increased costs to prevent, respond to or mitigate cybersecurity events.
Some of our office personnel are on a “remote work” model. This model has significantly increased the use of remote networking and online conferencing services that enable employees to work outside of our corporate infrastructure and, in some cases, use their own personal devices. This may expose us to additional cybersecurity risks or related incidents. Additionally, geopolitical tensions or conflicts may further heighten the risk of cybersecurity attacks and other cyber events. In particular, sophisticated nation state actors have targeted critical infrastructure and may continue to do so in the future.
Although we utilize various procedures and controls to mitigate our exposure to or limit the effects of the risks described above, cybersecurity attacks and other cyber events are evolving and unpredictable. In addition, there has been an increase in state-sponsored cyberattacks, which are often conducted by capable, well-funded groups. The rapid evolution and increased adoption of artificial intelligence technologies amplifies these concerns. There can be no assurance that the procedures and controls that we implement, or that our third party service providers implement, will be sufficient to protect our people, systems, information or other property. Moreover, we have no control over the information technology systems of our customers, suppliers, and others with which our systems may connect and communicate. As a result, the occurrence of a cyber incident could go unnoticed for a period of time. Even when an attack has been detected, it is not always immediately apparent what the full nature and scope of any potential harm may be, or how best to remediate it. We self-insure most of our cybersecurity risks, and any such incident could have a material adverse effect on our business, financial condition, cash flows and results of operations. As cyber incidents continue to evolve, we may be required to incur additional costs to continue to modify or enhance our protective measures or to investigate or remediate the effects of cyber incidents.
Our commitments under supply agreements could exceed our requirements, exposing us to risks including price, timing of delivery and quality of equipment and materials upon which our business relies.
We have purchase commitments with certain vendors to supply equipment and materials, including, in the case of our completion services business, proppants. Some of these agreements are take-or-pay or similar agreements with minimum purchase obligations. If demand for our services decreases from current levels, demand for the equipment that we use and the materials that we supply as part of these services will also decrease. In addition, our customers may self-source certain materials. If demand for our services and/or materials decreases enough, we could have contractual minimum commitments that exceed the required amount of materials we need to supply to our customers. In this instance, we could be required to purchase materials that we do not have a present need for, pay for materials that we do not take delivery of or pay prices in excess of market prices at the time of purchase.
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Growth through acquisitions, the building or upgrading of equipment and the development of technology is not assured.
We have grown our drilling rig fleet and completion services fleet and expanded our business lines and use of technology in the past through mergers, acquisitions, upgrades, new construction and technology development. For example, in 2023, we significantly expanded our completions business through the NexTier merger, and we added a specialized drill bit solutions business through the Ulterra acquisition. There can be no assurance that acquisition opportunities will be available in the future or that we will be able to execute timely or efficiently any plans for building or upgrading equipment or developing or acquiring new technology. We are also likely to continue to face intense competition from other companies for available acquisition opportunities. In addition, because improved technology has enhanced the ability to recover oil and natural gas, our competitors may continue to upgrade and build new equipment and develop new technology, including drilling automation technology and lower-emissions operations and services.
There can be no assurance that we will:
•successfully complete any acquisitions we attempt on the terms announced, or at all,
•have sufficient capital resources to complete additional acquisitions, build or upgrade equipment or develop or acquire new technology,
•through due diligence conducted prior to an acquisition, successfully uncover situations that could result in financial or legal exposure, or appropriately quantify the exposure from known risks,
•successfully integrate additional equipment, acquired or developed technology or other assets or businesses, including the combination of our business with the businesses of NexTier and Ulterra, into our operations and internal controls, including financial reporting disclosure and enterprise resource planning, cybersecurity and information technology systems,
•effectively manage the growth and increased size, complexity and geography of our organization, and increased scrutiny from governmental authorities,
•maintain existing business relationships and contract terms with our customers, distributors, suppliers, vendors, landlords, joint venture partners and other business partners, as well as with those of any acquired business,
•successfully deploy idle, stacked, upgraded or additional equipment and acquired or developed technology,
•maintain key employees, the crews necessary to operate additional equipment, and the personnel necessary to evaluate, acquire, develop and deploy new technology, or be successful in hiring replacements for departing personnel,
•avoid unknown liabilities and unforeseen increased expenses or delays associated with any merger or acquisition, or
•successfully improve our financial condition, results of operations, business or prospects, or provide an adequate return of capital, as a result of any completed acquisition, the building or upgrading equipment or the development of new technology.
Our failure to achieve consolidation savings, to integrate acquired businesses and technology and other assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our business. In addition, we may incur liabilities arising from events occurring prior to any completed acquisitions, prior to our establishment of adequate compliance oversight or in connection with disputes over acquired or developed technology. While we generally seek to obtain indemnities or insurance for liabilities arising from events occurring before such acquisitions, we may be unable to do so, and any indemnities or insurance we do obtain will be limited in amount and duration, and indemnities may be held to be unenforceable or the seller may not be able to indemnify us.
We may incur substantial indebtedness to finance future acquisitions, build or upgrade equipment or acquire or develop new technology, and we also may issue equity, convertible or debt securities in connection with any such acquisitions, building or upgrade program or technology development. Use of cash for these purposes may adversely affect our cash available for capital expenditures and other uses, debt service requirements could represent a significant burden on our results of operations and financial condition, and the issuance of additional equity or convertible securities could be dilutive to existing stockholders. Also, continued growth and resulting integration efforts could strain our management, operations, employees and other resources.
Complications with the design or implementation of our new enterprise resource planning system could adversely impact our business and operations.
We rely extensively on information systems and technology to manage our business and summarize operating results. We are in the process of implementing a new enterprise resource planning (“ERP”) system that expands and enhances one of our existing ERP systems to address the operations of our combined company. This ERP system will replace our existing operating and financial systems. The ERP system is designed to accurately maintain our financial records, enhance operational functionality and provide
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timely information to our management team related to the operation of our integrated business. The ERP system implementation process will require the investment of significant personnel and financial resources. We may be unable to successfully implement the ERP system without experiencing delays, increased costs and other difficulties. If we are unable to successfully design and implement the new ERP system as planned, our financial position, results of operations and cash flows could be negatively impacted. Additionally, if we do not effectively implement the ERP system as planned or the ERP system does not operate as intended, the effectiveness of our internal control over financial reporting and disclosure controls and procedures could be adversely affected or our ability to assess those controls adequately could be delayed.
Fuel conservation measures, alternative fuel requirements and increasing consumer demand for alternatives to oil and natural gas could reduce demand for oil and natural gas, which would, in turn, reduce the demand for our services.
Fuel conservation measures, alternative fuel requirements and increasing consumer demand for alternatives to oil and natural gas could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas may have a material adverse effect on our business, financial condition, cash flows and results of operations. Additionally, the increased competitiveness of alternative energy sources (such as wind, solar geothermal, tidal, and biofuels) or increased focus on reducing the use of oil and natural gas (such as governmental mandates that ban the sale of new gasoline-powered automobiles, and new legislation such as the Inflation Reduction Act of 2022, which contains tax inducements and other provisions that incentivize investment, development, and deployment of alternative energy sources and technologies) could reduce demand for oil and natural gas and therefore for our services, which would lead to a reduction in our revenues.
Legal and Regulatory Risks
The adoption of any future federal, state, or local laws or implementing regulations imposing reporting obligations on, or limiting or banning, the hydraulic fracturing process could make it more difficult to complete natural gas and oil wells and could have a material adverse effect on our business, results of operations, and financial condition.
Various federal and state legislative and regulatory initiatives have been or could be undertaken that could result in additional requirements or restrictions being imposed on hydraulic fracturing operations or result in the failure to obtain or difficulty or delay in obtaining required permits, renewals or authorizations. For example, legislation and/or regulations have been adopted in many U.S. states that require additional disclosure regarding chemicals used in the hydraulic fracturing process. Legislation, regulations, and/or policies have also been adopted at the state level that impose other types of requirements on hydraulic fracturing operations (such as limits on operations in the event of certain levels of seismic activity). Additional legislation and/or regulations have been adopted or are being considered at the state and local level that could impose further chemical disclosure or other regulatory requirements (such as prohibitions on hydraulic fracturing operations in certain areas) and/or other limitations on hydraulic fracturing operations via time, place, and manner restrictions) that could affect our operations, and it is possible that these state and local efforts may increase in the absence of federal actions and/or in light of federal regulatory uncertainty. Four states (New York, Maryland, Vermont, and Washington) have banned the use of high volume hydraulic fracturing, Oregon has adopted a five-year moratorium, California has taken regulatory action to phase out hydraulic fracturing permitting and activities in the state, and Colorado has enacted legislation providing local governments with regulatory authority over hydraulic fracturing operations. Local jurisdictions in some states have adopted ordinances that restrict or in certain cases prohibit the use of hydraulic fracturing, although many of these ordinances have been challenged and some have been overturned. The adoption of any future federal, state or local laws or regulations imposing reporting obligations on, or limiting or banning, the hydraulic fracturing process could make it more difficult to complete natural gas and oil wells and could have a material adverse effect on our business, results of operations, and financial condition.
Our and our customers’ operations are subject to a number of risks arising out of the threat of climate change that could result in increased operating and capital costs, limit the areas in which oil and natural gas production may occur and reduce demand for our services.
The physical and regulatory effects of climate change could have a negative impact on our operations, our customers’ operations and the overall demand for our customers’ products and, accordingly, our services. There is an increasing focus of local, state, regional, national and international regulatory bodies on GHG emissions and climate change issues. Legislation to regulate GHG emissions has periodically been introduced in the U.S. Congress, and there has been a wide-ranging policy debate, both in the United States and internationally, regarding the impact of these gases and possible means for their regulation. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting, tracking programs, attestation requirements and regulations that directly limit GHG emissions from certain sources. Some of the proposals would require industries to meet stringent new standards that would require substantial reductions in carbon emissions. Those reductions could be costly and difficult to implement. In addition to such legislative efforts, the EPA has determined that GHG emissions present a danger to public health and the environment and has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain oil and natural gas system sources, implement CAA emission standards directing the reduction of methane emissions from certain new,
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modified, or reconstructed facilities in the oil and natural gas sector, and together with the U.S. Department of Transportation, implement GHG emissions limits on vehicles manufactured for operation in the United States. For example, generators are subject to limits on their emissions of other hazardous air pollutants including mercury under an expanded Mercury and Air Toxics Standards rule adopted by the Biden Administration in 2024. In December 2023, the EPA issued a final rule updating New Source Performance Standards (NSPS) and providing emission guidelines to reduce methane and other pollutants from the oil and gas industry. Additionally, the location and operation of oil and natural gas production is impacted by laws concerning impacts to protected species and their habitats. The federal Endangered Species Act, as amended (“ESA”), restricts activities in the United States that may affect endangered or threatened species and/or their habitats. If endangered species and/or their habitats are located in areas of the United States with oil and natural gas exploration and production operations, such operations can be prohibited or delayed or require potentially costly mitigation efforts. Additionally, in the absence of federal action and listing of endangered species and habitats, states and local governments may increasingly attempt to step in to subject such species and habitats to state protections under analogous state statutes. Changes to the designation of previously unprotected species as threatened or endangered or designation of previously unprotected habitat as critical habitat in areas of the United States can result in limitations on exploration and production activities, impacting our and our customers’ operating costs and demand for services.
In November 2021, the United States and other countries entered into the Glasgow Climate Pact, which includes a range of measures designed to address climate change, including but not limited to the phase-out of fossil fuel subsidies, reducing methane emissions 30% by 2030, and cooperating toward the advancement of the development of clean energy. Several states and geographic regions in the United States have also adopted legislation and regulations to reduce emissions of GHGs, including cap and trade regimes and commitments to contribute to meeting certain emissions reduction goals.
Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States. A number of new GHG-related initiatives went into effect under the prior Biden Administration, which initiatives may be modified or reversed under the Trump Administration. The Trump Administration may diverge from the Biden Administration’s positions and could withdraw from or otherwise roll back existing GHG commitments. For example, in January 2025, President Trump signed an executive order to withdraw the United States from the Paris Agreement. While it is not possible at this time to predict exactly which and to what extent such commitments will be modified, and how any such actions may impact our business, such actions could prompt more activity from state and local legislative bodies and administrative agencies to pass stricter GHG laws, regulations, and other binding commitments.
It is not possible at this time to predict the timing and effects of climate change or whether additional climate-related legislation, regulations or other measures will be adopted at the local, state, regional, national and international levels. However, continued efforts by governments and non-governmental organizations to reduce GHG emissions appear likely, and additional legislation, regulation or other measures that control or limit GHG emissions or otherwise seek to address climate change could adversely affect our business. The cost of complying with any new law, regulation or treaty will depend on the details of the particular program. We will continue to monitor and assess any new policies, legislation or regulations in the areas where we operate to determine the impact of GHG emissions and climate change on our operations and take appropriate actions, where necessary. Any direct and indirect costs of meeting these requirements may adversely affect our business, results of operations and financial condition. Because our business depends on the level of activity in the oil and natural gas industry, existing or future laws or regulations related to GHGs and climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on our business if such laws or regulations increase compliance costs, add operating restrictions, or reduce demand for our customers’ products and, accordingly, our services.
Increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits or investigations brought by public and private entities against oil and natural gas companies in connection with their GHG emissions. Should we be targeted by any such litigation or investigations, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to the causation of or contribution to the asserted damage, or to other mitigating factors.
These political, litigation, and financial risks may result in our customers restricting or cancelling production activities, incurring liability for infrastructure damage as a result of climatic changes, or impairing their ability to continue to operate in an economic manner, which also could reduce demand for our products and services. One or more of these developments could have a material adverse effect on our business, financial condition, cash flows and results of operations. Finally, increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our and our customers’ facilities and operations.
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Environmental and occupational health and safety laws and regulations, including violations thereof, could materially adversely affect our operating results.
Our business is subject to numerous federal, state, foreign, regional and local laws, rules and regulations governing the discharge of substances into the environment, protection of the environment and worker health and safety, including, without limitation, laws concerning the containment and disposal of hazardous substances, oil field waste and other waste materials, the use of underground storage tanks, and the use of underground injection wells. The cost of compliance with these laws and regulations could be substantial.
For example, in the United States, the Comprehensive Environmental Response Compensation and Liability Act of 1980, as amended (“CERCLA”), and comparable state statutes impose strict liability on owners and operators of sites, including prior owners and operators who are no longer active at a site, as well as persons who disposed of or arranged for the disposal of “hazardous substances” found at sites.
The Resource Conservation and Recovery Act (“RCRA”), as amended, and comparable state statutes and implementing regulations govern the disposal of “hazardous wastes.” Although CERCLA currently excludes petroleum from the definition of “hazardous substances,” and RCRA also excludes certain classes of exploration and production wastes from regulation, such exemptions may be deleted, limited, or modified in the future. The Clean Water Act (“CWA”) and analogous state laws provide for administrative, civil and criminal penalties for unauthorized discharges and, together with the Oil Pollution Act of 1999, as amended, impose liability for the remedial costs and associated damages arising out of any unauthorized discharges, including oil and produced water spills, into jurisdictional waters.
Our operations are also subject to federal, state, foreign, regional and local laws, rules and regulations for the control of air emissions, including those associated with the Clean Air Act. We and our customers may be required to make capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We are also subject to regulation by numerous other regulatory agencies, including, but not limited to, the U.S. Department of Labor, which oversees employment practice standards.
Furthermore, the U.S. Occupational Safety and Health Administration (“OSHA”) promulgates and enforces laws and regulations governing the protection of the health and safety of employees. The OSHA hazard communication standard, EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governments and citizens. Also, OSHA has established a variety of standards related to workplace exposure to hazardous substances and employee health and safety.
Other jurisdictions where we may conduct operations have similar environmental, employee health and safety and other regulatory regimes with which we would be required to comply. These laws, rules and regulations also require that facility sites and other properties associated with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, new projects or changes to existing projects may require the submission and approval of environmental assessments or permit applications. These laws, rules and regulations are subject to frequent change, and the clear trend is to place increasingly stringent limitations on activities that may affect the environment.
A failure to comply with these requirements could expose us to:
•substantial civil, criminal and/or administrative penalties or judgments,
•modification, denial or revocation of permits or other authorizations,
•imposition of limitations on our operations, and
•performance of site investigatory, remedial or other corrective actions.
In addition, environmental laws and regulations in the places that we operate impose a variety of requirements on “responsible parties” related to the prevention of spills and liability for damages from such spills. As an owner and operator of land-based drilling rigs and completion services equipment, a manufacturer and servicer of equipment and automation to the energy, marine and mining industries and a provider of directional drilling and other services, we may be deemed to be a responsible party under these laws and regulations. In the event hydrocarbons and other materials may have been disposed of, or released in or under properties currently or formerly owned or operated by us or our predecessors, which may have resulted, or may result, in soil and groundwater contamination in certain locations, any contamination found on, under or originating from the properties may be subject to remediation requirements under federal, state, foreign, regional and local laws, rules and regulations. In addition, some of these properties have been operated by third parties over whom we have no control of their treatment of hydrocarbon and other materials or the manner in which they may have disposed of or released such materials. We could be required to remove or remediate wastes disposed of or released by prior
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owners or operators. In addition, it is possible we could be held responsible for oil and natural gas properties in which we own an interest but are not the operator.
Intellectual property disputes could negatively impact our operations, costs, revenues and competitiveness.
Our services and products use proprietary technology and equipment, which can involve potential infringement of a third party’s rights, or a third party’s infringement of our rights, including patent rights. The majority of the intellectual property rights relating to our drilling services equipment, completion services equipment, and drilling products are owned by us or certain of our supplying vendors. However, in the event that we or one of our customers or supplying vendors becomes involved in a dispute over infringement of intellectual property rights relating to equipment or technology owned or used by us, services performed by us or products provided by us, we may lose access to important equipment or technology or our ability to provide services or products, or we could be required to cease use of some equipment or technology or forced to modify our equipment, technology, services or products. We could also be required to pay license fees or royalties for the use of equipment or technology or provision of services or products. In addition, we may lose a competitive advantage in the event we are unsuccessful in enforcing our rights against third parties, third parties are successful in enforcing their rights against us, or our competitors are able to develop technology independently that is similar to ours without infringing on our patents or gaining access to our trade secrets.
Regardless of the merits, any such claims may result in significant legal and other costs, including reputational harm, and may distract management from running our business. Some of our competitors and current and potential vendors have a substantial amount of intellectual property related to new equipment and technologies. We cannot guarantee that our equipment, technology, services or products will not be determined to infringe currently issued or future issued patents or other intellectual property rights belonging to others, including, without limitation, situations in which our equipment, technology, services or products may be covered by patent applications filed by other parties. Technology disputes involving us or our customers or supplying vendors could have a material adverse impact on our business, financial condition, cash flows and results of operations.
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. An unfavorable judgment or resolution of this claim not covered by indemnity could have a material impact on our financial results.
The design, manufacture, sale or rental and servicing of products, including drill bits and electrical controls, may subject us to liability for personal injury, property damage and environmental contamination.
We provide products, including specialized drill bit solutions and electrical controls, to customers involved in oil and natural gas exploration, development and production and in the marine and mining industries. Because of applications that use our products and services, a failure of such equipment, or a failure of our customer to maintain or operate the equipment properly, could cause harm to our reputation, contractual and warranty-related liability, damage to the equipment, damage to the property of customers and others, personal injury and environmental contamination, leading to claims against us. Any lawsuits or claims against us could have a material adverse effect on our business, financial condition and results of operations.
Legal proceedings and governmental investigations could have a negative impact on our business, financial condition and results of operations.
The nature of our business makes us susceptible to legal proceedings and governmental investigations from time to time. In addition, during periods of depressed market conditions, we may be subject to an increased risk of our customers, vendors, current and former employees and others initiating legal proceedings against us. Lawsuits or claims against us could have a material adverse effect on our business, financial condition and results of operations. Any legal proceedings or claims, even if fully indemnified or insured, could negatively affect our reputation among our customers and the public, and make it more difficult for us to compete effectively or obtain adequate insurance in the future. Please see “Our operations are subject to a number of operational risks, including environmental and weather risks, which could expose us to significant losses and damage claims. We are not fully insured against all of these risks and our contractual indemnity provisions may not fully protect us.”
Political, economic and social instability risk and laws associated with conducting international operations could adversely affect our opportunities and future business.
We provide specialized drill bit solutions throughout North America and internationally in over 30 countries, as well as contract drilling services in Colombia and Ecuador. We also sell products, including electrical controls, for use in numerous oil and natural gas producing regions outside of North America. In addition, through our Superior QC business, we occasionally provide remote data analytics and other services to customers to support their operations outside of the United States. One of our subsidiaries recently closed a joint venture in Abu Dhabi. We also continue to evaluate opportunities from time to time to provide our services and products
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outside of the United States. International operations and sales or rentals of products are subject to certain political, economic and other uncertainties generally not encountered in U.S. operations, including increased risks of social and political unrest, changing political conditions and changing laws and policies affecting trade and investment, strikes, work stoppages, labor disputes and other slowdowns, terrorism, war, kidnapping of employees, blockades, regional economic downturns, nationalization, forced negotiation or modification of contracts, difficulty resolving disputes and enforcing contractual rights, difficulty in collecting international accounts receivable, potentially longer payment cycles, expropriation of equipment as well as expropriation of oil and natural gas exploration and drilling rights, foreign taxation and customs regulations, the overlap of different tax structures, changes in taxation policies, foreign exchange restrictions and restrictions on repatriation of income and capital, currency rate fluctuations, increased governmental ownership and regulation of the economy and industry in the markets in which we may operate, economic and financial instability of national oil companies, and restrictive governmental regulation, bureaucratic delays and general hazards associated with foreign sovereignty over certain areas in which operations are conducted.
There can be no assurance that there will not be changes in local laws, regulations and administrative requirements, or the interpretation thereof, which could have a material adverse effect on the cost of entry into international markets, the profitability of international operations or the ability to continue those operations in certain areas. Because of the impact of local laws, any current and future international operations in certain areas may be conducted through entities in which local citizens own interests and through entities (including joint ventures, such as our Abu Dhabi joint venture) in which we hold only a minority interest or pursuant to arrangements under which we conduct operations under contract to local entities. While we do not control the actions of our joint venture partners, their actions could have an effect on our investment in the joint ventures and more generally our overall reputation. While we believe that neither operating through such entities nor pursuant to such arrangements would have a material adverse effect on our operations or revenues, there can be no assurance that we will in all cases be able to structure or restructure our operations to conform to local law (or the administration thereof) on terms we find acceptable. Additionally, we may be subject to foreign governmental regulations favoring or requiring the awarding of contracts to local contractors or requiring foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These regulations could adversely affect our ability to compete.
There can be no assurance that we will:
•identify attractive opportunities in international markets,
•have sufficient capital resources to pursue and consummate international opportunities,
•successfully integrate international drilling and completion operations or other assets or businesses,
•effectively manage the start-up, development and growth of an international organization and assets,
•hire, attract and retain the personnel necessary to successfully conduct international operations, or
•receive awards for work and successfully improve our financial condition, results of operations, business or prospects as a result of the entry into one or more international markets.
In addition, the U.S. Foreign Corrupt Practices Act (“FCPA”) and similar anti-bribery laws in other jurisdictions generally prohibit companies and their intermediaries from making improper payments to foreign officials for the purpose of obtaining or retaining business. Some parts of the world where our services are or could be provided or where our consumers for products are located have experienced governmental corruption to some degree and, in certain circumstances, strict compliance with anti-bribery laws may conflict with local customs and practice and could impact business. Any failure to comply with the FCPA or other anti-bribery legislation could subject to us to civil, criminal and/or administrative penalties or other sanctions, which could have a material adverse impact on our business, financial condition and results of operation. In addition, investors could negatively view potential violations, inquiries or allegations of misconduct under the FCPA or similar laws, which could adversely affect our reputation and the market for our shares. We could also face fines, sanctions and other penalties from authorities in the relevant foreign jurisdictions, including prohibition of our participating in or curtailment of business operations in those jurisdictions and the seizure of drilling rigs, completion services equipment, manufacturing facilities, drilling products or other assets.
Many countries, including the United States, control the import and export of certain goods, services and technology and impose related import and export recordkeeping and reporting obligations. Governments also may impose economic sanctions against certain countries, persons and other entities that may restrict or prohibit transactions involving such countries, persons and entities. In particular, U.S. sanctions are targeted against certain countries that are heavily involved in the oil and natural gas industry. The laws and regulations concerning import and export activity, recordkeeping and reporting, including customs, export controls and economic sanctions, are complex and constantly changing. Any failure to comply with applicable legal or regulatory requirements governing international trade could also result in criminal and civil penalties and sanctions, such as fines, imprisonment, debarment from government contracts, seizure of shipments and loss of import and export privileges.
We may incur substantial indebtedness to finance an international transaction or operations, and we also may issue equity, convertible or debt securities in connection with any such transactions or operations. Debt service requirements could represent a significant burden on our results of operations and financial condition, and the issuance of additional equity or convertible securities
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could be dilutive to existing stockholders. Also, international expansion could strain our management, operations, employees and other resources.
The occurrence of one or more events arising from the types of risks described above could have a material adverse impact on our business, financial condition and results of operations.
We are subject to complex and evolving laws and regulations regarding data privacy and security.
Governments around the world have implemented, and continue to implement, laws and regulations regarding data privacy and security, including with respect to the protection and processing of personal employee and customer data. These laws and regulations vary from jurisdiction to jurisdiction, and we are obligated to comply in all jurisdictions in which we conduct business. In the normal course of business, we and our third-party vendors or service providers may collect, process, and store data that is subject to those specific laws and regulations governing personal data. Failure to comply with these laws and regulations could subject us to significant liability, including fines, penalties, and potential criminal sanctions.
Financial Risks
Investor sentiment and public perception related to the oil and natural gas industry and to ESG initiatives could increase our costs of capital and our reporting requirements and impact our operations.
There are financial risks for oil and natural gas producers, as stockholders and bondholders currently invested in oil and natural gas companies and concerned about the potential effects of climate change, ESG and other sustainability-related issues may elect in the future to shift some or all of their investments into non-fossil fuel energy related sectors, or into competitors who are perceived to have stronger ESG practices and disclosures. At the same time, some stakeholders and regulators have increasingly expressed or pursued opposing views, legislation, and investment expectations with respect to ESG, including the enactment or proposal of “anti-ESG” legislation or policies. In addition, other parties such institutional lenders may consider sustainability factors in lending to us or our customers. Limitations of investments in and financing for oil and natural gas could result in the restriction, delay, or cancellation of drilling and completion programs or development of production activities. Our ESG practices and, through the publishing of our Sustainability Report from time to time, disclosures may be subject to increased scrutiny and may not satisfy the requirements of all stakeholders or their requirements may not be made known to us. We may continue to face pressure regarding our ESG practices and disclosures.
We have developed, and will continue to develop, goals and other objectives related to ESG and sustainability matters. Statements related to these goals and objectives made in our published Sustainability Report and other public disclosure reflect our current plans and do not constitute a guarantee that they will be achieved. Our ability to achieve any stated goal or objective is subject to numerous factors and conditions, some of which are outside of our control. Our efforts to accurately report on ESG and sustainability matters, including our efforts to research, establish, accomplish and accurately report on our goals and objectives, expose us to numerous operational, reputational, financial, legal, and other risks. Standards for tracking and reporting on ESG and sustainability matters, including climate-related matters, have not been harmonized and continue to evolve. Our processes and controls for reporting on ESG and sustainability matters, including our goals and objectives, may not always comply with evolving and disparate standards for identifying, measuring, disclosing and reporting such metrics, and such standards may change over time, which could result in significant revisions to our current ESG practices and disclosures.
Variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.
In January 2025, we put in place a committed senior unsecured revolving credit facility that amended the Prior Credit Agreement. Under the Credit Agreement, interest is paid on the outstanding principal amount of borrowings under the credit facility at a floating rate based on, at our election, the SOFR rate (plus a 0.10% per annum adjustment) or base rate, in each case subject to a 0.00% floor. Under the Credit Agreement, 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 December 31, 2024, under the Prior Credit Agreement, the applicable margin on SOFR rate loans was 1.75% and the applicable margin on base rate loans was 0.75%. As of December 31, 2024, we had no borrowings outstanding under the Prior Credit Agreement.
We also have in place a reimbursement agreement pursuant to which we are required to reimburse the issuing bank on demand for any amounts that it has disbursed under any of our letters of credit issued thereunder. We are obligated to pay the issuing bank 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. As of December 31, 2024, no amounts had been disbursed under any letters of credit, and we had $38.8 million in letters of credit outstanding under the reimbursement agreement.
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Interest rates could rise for various reasons in the future and increase our total interest expense, depending upon the amounts borrowed at floating rates under these agreements or under future agreements, as well as the terms of any future amendments to our existing agreements or future agreements.
Our ability to access capital markets could be limited, and a downgrade in our credit rating could negatively impact our cost of and ability to access capital.
From time to time, we may need to access capital markets to obtain financing. Our ability to access capital markets for financing could be limited by oil and natural gas prices, our existing capital structure, the state of the economy, the health or market perceptions of the drilling and overall oil and natural gas industry, the liquidity of the capital markets and ESG-related regulatory and investor requirements and other factors. Many of the factors that affect our ability to access capital markets are outside of our control. No assurance can be given that we will be able to access capital markets on terms acceptable to us when required to do so, which could have a material adverse impact on our business, financial condition and results of operations.
Additionally, our ability to access capital markets or to otherwise obtain sufficient financing is enhanced by our senior unsecured debt ratings as provided by major U.S. credit rating agencies. Factors that may impact our credit ratings include debt levels, liquidity, asset quality, cost structure, commodity pricing levels, industry conditions and other considerations. A ratings downgrade could adversely impact our ability in the future to access debt markets, increase the cost of future debt, impact the terms of future amendments to our senior unsecured credit facility and potentially require us to post letters of credit for certain obligations.
We may not be able to generate sufficient cash to service all of our debt and we may be forced to take other actions to satisfy our obligations under our debt, which may not be successful.
Our ability to make scheduled payments on or to refinance our debt obligations depends on our financial and operating performance, including the ability of our subsidiaries to generate sufficient cash flows, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control. We cannot assure you that we will maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.
In addition, if our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay capital expenditures, sell assets or operations, seek additional capital or restructure or refinance our debt. We cannot assure you that we would be able to take any of these actions, that these actions would be successful and would permit us to meet our scheduled debt service obligations or that these actions would be permitted under the terms of our existing or future debt agreements. In the absence of such cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. However, our debt agreements contain restrictions on our ability to dispose of assets. We may not be able to consummate those dispositions, and any proceeds may not be adequate to meet any debt service obligations then due.
Our return of capital to stockholders, including through the payment of dividends and repurchases of our common stock, is within the discretion of our Board of Directors, and there is no guarantee that we will return capital to shareholders, including through the payment of dividends and repurchases of our common stock, in the future or at levels anticipated by our stockholders.
Although we currently plan to return capital to stockholders, the amount and timing of returns of capital to stockholders may vary from time to time. The amount and timing of all returns of capital, including future dividend payments and purchases pursuant to our stock buyback program, 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 or limit, suspend or terminate our stock repurchase program. There can be no assurance that we will pay a dividend or make repurchases of our common stock in the future. The payment of dividends and stock repurchases could diminish our cash reserves, which may impact our ability to meet our working capital needs, satisfy our debt obligations, make capital expenditures, grow and pursue strategic opportunities and acquisitions. In addition, any elimination of, or downward revision in, our stock buyback program or dividend payments could have an adverse effect on the market price of our common stock.
Our ability to utilize our historic U.S. net operating loss carryforwards is expected to be limited as a result of the completion of the NexTier merger.
As of December 31, 2024, we had approximately $1.5 billion of gross U.S. federal net operating losses, approximately $58.7 million of gross Canadian net operating losses and approximately $910 million of post-apportionment U.S. state net operating losses as of December 31, 2024, before valuation allowances. The majority of the U.S. federal net operating losses are generated after 2017
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and can be carried forward indefinitely. Canadian net operating losses will expire in varying amounts, if unused, between 2036 and 2044. U.S. state net operating losses will expire in varying amounts, if unused, between 2025 and 2044.
Section 382 of the Internal Revenue Code (“Section 382”) generally imposes an annual limitation on the amount of NOLs that may be used to offset taxable income when a corporation has undergone an “ownership change” (as determined under Section 382). An ownership change generally occurs if one or more stockholders (or groups of stockholders) who are each deemed to own at least 5% of such corporation’s stock has increased their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling three-year period. In the event that an ownership change occurs, utilization of the relevant corporation’s NOLs would be subject to an annual limitation under Section 382, generally determined, subject to certain adjustments, by multiplying (i) the fair market value of such corporation’s stock at the time of the ownership change by (ii) a percentage approximately equivalent to the yield on long-term tax-exempt bonds during the month in which the ownership change occurs. Any unused annual limitation may be carried over to later years.
We experienced an ownership change (under Section 382) as a result of the closing of the NexTier merger. Our ability to utilize our available NOLs and other tax attributes to reduce future taxable income following this “ownership change” depends on many factors, including our future income, which cannot be assured. Based on information currently available, we expect this ownership change could cause some of our NOLs incurred prior to January 1, 2018 to expire before we would be able to utilize them to reduce taxable income in future periods, and may also require NOLs to be utilized later than they otherwise would be able to be utilized, increasing cash taxes payable in earlier years.
Risks Related to Our Common Stock and Corporate Structure
The market price of our common stock may be highly volatile, and investors may not be able to resell shares at or above the price paid.
The trading price of our common stock may be volatile. Securities markets worldwide experience significant price and volume fluctuations. This market volatility, as well as other general economic, market or political conditions, could reduce the market price of our common stock in spite of our operating and/or financial performance. The following factors, in addition to other factors described in this “Risk Factors” section and elsewhere in this Report, may have a significant impact on the market price of our common stock:
•investor perception of us and the industry and markets in which we operate;
•general financial, domestic, international, economic, and market conditions, including overall fluctuations in the U.S. equity markets;
•increased focus by the investment community on sustainability practices at our company and in the oil and natural gas industry generally;
•changes in customer needs, expectations or trends and our ability to maintain relationships with key customers;
•our ability to implement our business strategy;
•changes in our capital structure, including the issuance of additional debt;
•public announcements (including the timing of these announcements) regarding our business, financial performance and prospects or new services or products, service or product enhancements, technological advances or strategic actions, such as acquisitions or divestitures, restructurings or significant contracts, by our competitors or us;
•trading activity in our stock, including portfolio transactions in our stock by us, our executive officers and directors, and significant stockholders or trading activity that results from the ordinary course rebalancing of stock indices in which we may be included;
•any elimination of, or downward revision in, our stock buyback program or dividend payments;
•short-interest in our common stock, which could be significant from time to time;
•our inclusion in, or removal from, any stock indices;
•changes in earnings estimates or buy/sell recommendations by securities analysts;
•whether or not we meet earnings estimates of securities analysts who follow us; and
•regulatory or legal developments in the United States and the foreign countries where we operate.
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Anti-takeover measures in our charter documents and under state law could discourage an acquisition and thereby affect the related purchase price.
We are a Delaware corporation subject to the Delaware General Corporation Law, including Section 203, an anti-takeover law. Our restated certificate of incorporation authorizes our Board of Directors to issue up to one million shares of preferred stock and to determine the price, rights (including voting rights), conversion ratios, preferences and privileges of that stock without further vote or action by the holders of the common stock. It also prohibits stockholders from acting by written consent without the holding of a meeting. In addition, our bylaws impose certain advance notification requirements as to business that can be brought by a stockholder before annual stockholder meetings and as to persons nominated as directors by a stockholder. As a result of these measures and others, potential acquirers might find it more difficult or be discouraged from attempting to effect an acquisition transaction with us. This may deprive holders of our securities of certain opportunities to sell or otherwise dispose of the securities at above-market prices pursuant to any such transactions.
Our bylaws provide that the Court of Chancery of the State of Delaware and the federal district courts of the United States are the exclusive forums for substantially all disputes between us and our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers or employees.
Our bylaws provide that, to the fullest extent permitted by law, the Court of Chancery of the State of Delaware (or, if the Court of Chancery does not have, or declines to accept, jurisdiction, another state court or a federal court located within the State of Delaware) is the exclusive forum for any claims, including claims in the right of Patterson-UTI: (a) that are based upon a violation of a duty by a current or former director, officer, employee or stockholder in such capacity, or (b) as to which the General Corporation Law of the State of Delaware confers jurisdiction upon the Court of Chancery. This provision would not apply to suits brought to enforce a duty or liability created by the Exchange Act or any other claim for which the U.S. federal courts have exclusive jurisdiction. Our bylaws further provide that the sole and exclusive forum for any complaint asserting a cause of action arising under the Securities Act, to the fullest extent permitted by law, shall be the federal district courts of the United States. The enforceability of similar exclusive federal forum provisions in other companies’ organizational documents has been challenged in legal proceedings, and while the Delaware Supreme Court has ruled that this type of exclusive federal forum provision is facially valid under Delaware law, there is uncertainty as to whether other courts would enforce such provisions and that investors cannot waive compliance with the federal securities laws and the rules and regulations thereunder. These exclusive forum provisions may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers or other employees, which may discourage such lawsuits against us and our directors, officers and other employees. Alternatively, if a court were to find either exclusive forum provision in our bylaws to be inapplicable or unenforceable in an action, we may incur additional costs associated with resolving such action in other jurisdictions, which could have a material adverse effect on our business, financial condition, and results of operations.
Item 1B. Unresolved Staff Comments.
None.
Item 1C. Cybersecurity
We have implemented and maintain a cybersecurity program that is aligned with the NIST Framework and designed to protect our information and to assess, identify, and manage risks from cybersecurity threats that may result in material adverse effects on the confidentiality, integrity, and availability of our information systems.
Governance
Our Board of Directors has delegated the primary responsibility to oversee cybersecurity matters to the Audit Committee. The Audit Committee periodically reviews the measures implemented by the Company to identify and mitigate data protection and cybersecurity risks. As part of such reviews, the Audit Committee receives reports and presentations from members of our senior leadership for overseeing the company’s cybersecurity risk management, including the Senior Vice President of Information Technology, which address a wide range of topics including recent developments, evolving standards, vulnerability assessments, third-party and independent reviews, the threat environment, technological trends and information security considerations arising with respect to the Company’s peers and third parties. We have protocols by which certain cybersecurity incidents are escalated within the Company and, where appropriate, reported promptly to the Board of Directors and Audit Committee.
Our Audit Committee is responsible for overseeing information security and cybersecurity risk. Senior leadership communicates with the Audit Committee at least quarterly regarding information security and cybersecurity risk and formally reports to the entire Board of Directors on information security and cybersecurity risk at least annually.
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At the management level, our Senior Vice President of Information Technology, who has extensive cybersecurity knowledge and skills gained from over 19 years of work experience at our company and elsewhere, heads the team responsible for implementing, monitoring, and maintaining information security and cybersecurity practices across our businesses and reports directly to our Chief Financial Officer.
The Senior Vice President of Information Technology receives reports on information security and cybersecurity threats from our Director of Infrastructure and Cybersecurity and in conjunction with management, regularly reviews risk management measures implemented by our company to identify and mitigate information security and cybersecurity risks. A number of experienced information security team members responsible for various parts of the business also report to the Senior Vice President of Information Technology on an ongoing basis. In addition to our internal cybersecurity capabilities, we also regularly engage assessors, consultants, auditors, and other third parties to assist with assessing, identifying, and managing cybersecurity risks.
We have adopted a cybersecurity incident reporting process (“IRP”) that applies in the event of a cybersecurity threat or incident to provide a standardized framework for response. The IRP sets out a coordinated approach to investigating, containing, documenting, and mitigating incidents, including reporting findings and keeping senior management, the Board of Directors and other key stakeholders informed and involved as appropriate.
Risk Management and Strategy
Our senior management and representatives from our business units regularly communicate with the Board of Directors on risk management matters, including cybersecurity risks. Senior management conducts regular risk assessments to identify risks that have the potential to significantly affect our business over the short-, medium- and longer term and reviews with the Board of Directors risk mitigation and oversight measures, including prioritization of risk management and allocation of responsibility within our company for the management of a particular risk.
We continue to improve our cybersecurity risk assessment program and activities for assessing, identifying and managing cybersecurity risks through industry standard security frameworks and leading practices, including risk assessments and remediations, software and services, continuous systems monitoring, vendor risk management processes, incident response plans, phishing simulations, employee training, tabletop exercises and communication programs, among other measures. We also employ processes designed to assess, identify, and manage the potential impact of a security incident at critical third-party vendors, service providers or customers or otherwise implicating the third-party technology and systems we use.
All employees with a company-provided email are assigned annual cyber awareness training. In addition, we perform monthly phishing simulations, with remediation training required as necessary.
While we have not experienced material cybersecurity threats or incidents, or threats or incidents that are reasonably likely to materially affect us, there can be no guarantee that we will not be the subject of future successful attacks, threats or incidents. Information on cybersecurity risks and threats we face can be found in Part I, Item 1A “Risk Factors” of this Report under the heading “Our business is subject to cybersecurity risks and threats.”
Item 2. Properties
Our property consists primarily of drilling rigs and related equipment, completion services equipment and rental bits. We own substantially all of the equipment used in our businesses.
Our corporate headquarters is in leased office space and is located at 10713 W. Sam Houston Parkway N., Suite 800, Houston, Texas, 77064. Our telephone number at that address is (281) 765-7100.
Drilling Services — Our drilling services are supported by multiple offices and yard facilities located throughout our areas of operations, including Texas, Oklahoma, Colorado, North Dakota, Wyoming, Pennsylvania, Ohio, and internationally in Colombia and Ecuador. Our servicing of equipment for drilling contractors is supported by offices and yard facilities located in Texas. Our electrical controls and automation operation is supported by an office and yard facility in Texas.
Completion Services — Our completion services are supported by multiple offices and yard facilities located in the Permian, Marcellus Shale/Utica Basins, Haynesville and Eagle Ford, among others.
Drilling Products — Our drilling products segment is supported by multiple offices and manufacturing and distributing facilities located throughout North America and internationally in over 30 countries.
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Other — Our oilfield rental operations are supported by offices and yard facilities located in Texas, Oklahoma and Ohio. Our interests in oil and natural gas assets are primarily located in Texas and New Mexico.
We own or lease administrative offices, manufacturing facilities, research centers, and other facilities throughout the world, none of which is individually material. We believe that our existing facilities are suitable and adequate to meet our needs.
We incorporate by reference in response to this item the information set forth in Item 1 of this Report and the information set forth in Note 6 of the Notes to Consolidated Financial Statements included in Item 8 of this Report.
Item 3. 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.
The case is Grant Prideco, Inc., et al. v. Schlumberger Technology Corp., et al., in Texas State Court, District of Harris County, 11th Judicial District. 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. 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.
Discovery is closed and dispositive motions are scheduled to be fully briefed by the end of March 2025. Trial is currently scheduled for March 31, 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 legal proceedings arising in the normal course of our business. We do not believe that the outcome of these proceedings, either individually or in the aggregate, will have a material adverse effect on our financial condition, cash flows and results of operations.
Item 4. Mine Safety Disclosure.
Not applicable.
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PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
(a)Market Information
Our common stock, par value $0.01 per share, is publicly traded on the Nasdaq Global Select Market and is quoted under the symbol “PTEN.” Our common stock is included in the S&P SmallCap 600 Index and several other market indices.
(b)Holders
As of February 6, 2025, there were approximately 800 holders of record of our common stock.
(c)Dividends
On February 5, 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 March 17, 2025 to holders of record as of March 3, 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.
(d)Issuer Purchases of Equity Securities
The table below sets forth the information with respect to purchases of our common stock made by us during the quarter ended December 31, 2024.

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)
October 2024 | 10,599 |  | $ | 8.32 |  |  | — |  | $ | 779,655 |
November 2024 | — |  | $ | — |  |  | — |  | $ | 779,655 |
December 2024 | 2,625,921 |  | $ | 7.89 |  |  | 2,625,921 |  | $ | 758,934 |
Total | 2,636,520 |  |  |  | 2,625,921 |  |

(1)10,599 shares were withheld in the fourth quarter 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.
(e)Performance Graph
The following graph compares the cumulative stockholder return of our common stock for the period from December 31, 2019 through December 31, 2024, with the cumulative total return of the S&P 500 Index, the S&P SmallCap 600 Index and the Oilfield Service Index.
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The graph assumes investment of $100 on December 31, 2019 and reinvestment of all dividends.
Index Data: Copyright Standard and Poor’s, Inc. Used with permission. All rights reserved.

|  | Fiscal Year Ended December 31,
Company/Index |  | 2019 ($) |  | 2020 ($) |  | 2021 ($) |  | 2022 ($) |  | 2023 ($) |  | 2024 ($)
Patterson-UTI Energy, Inc. |  | 100.00 |  |  | 51.19 |  |  | 83.08 |  |  | 167.56 |  |  | 110.30 |  |  | 87.21 |
S&P 500 Index |  | 100.00 |  |  | 118.39 |  |  | 152.34 |  |  | 124.73 |  |  | 157.48 |  |  | 196.85 |
S&P SmallCap 600 Index |  | 100.00 |  |  | 111.24 |  |  | 140.98 |  |  | 118.22 |  |  | 137.07 |  |  | 148.91 |
Oilfield Service Index |  | 100.00 |  |  | 57.92 |  |  | 69.94 |  |  | 112.94 |  |  | 115.10 |  |  | 101.68 |

The foregoing graph is based on historical data and is not necessarily indicative of future performance. This graph shall not be deemed to be “soliciting material” or to be “filed” with the SEC or subject to Regulations 14A or 14C under the Exchange Act or to the liabilities of Section 18 under such Act.
Item 6. RESERVED
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Item 7. 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.
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 December 31, 2024, 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 have been relatively range-bound since the end of 2022. The current demand for equipment and services remains impacted by macro conditions, including commodity prices, geopolitical environment, 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.
Oil prices averaged $70.73 per barrel in the fourth quarter of 2024 and closed at $73.52 per barrel on February 3, 2025. Natural gas prices (based on the Henry Hub Spot Market Price) averaged $2.45 per MMBtu in the fourth quarter of 2024 and closed at $3.30 per MMBtu on February 3, 2025.
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Quarterly average oil prices and our quarterly average number of rigs operating in the United States for 2022, 2023 and 2024 are as follows:

| 1 st Quarter |  | 2 nd Quarter |  | 3 rd Quarter |  | 4 th Quarter
2022 |  |  |  |  |  |  |
Average oil price per Bbl (1) | $ | 94.45 |  |  | $ | 108.72 |  |  | $ | 93.18 |  |  | $ | 82.79 |
Average rigs operating per day – U.S. (2) | 115 |  | 121 |  | 128 |  | 131
2023 |  |  |  |  |  |  |
Average oil price per Bbl (1) | $ | 75.93 |  |  | $ | 73.54 |  |  | $ | 82.25 |  |  | $ | 78.53 |
Average rigs operating per day – U.S. (2) | 131 |  | 128 |  | 120 |  | 118
2024 |  |  |  |  |  |  |
Average oil price per Bbl (1) | $ | 77.50 |  |  | $ | 81.81 |  |  | $ | 76.43 |  |  | $ | 70.73 |
Average rigs operating per day – U.S. (2) | 121 |  | 114 |  | 107 |  | 105 |

(1)The average oil price represents the average monthly WTI spot price as reported by the United States Energy Information Administration.
(2)A rig is considered to be operating if it is earning revenue pursuant to a contract on a given day.
In our drilling services segment, our average active rig count in the United States for the fourth quarter of 2024 was 105 rigs. This was a decrease from our average active rig count for the third quarter of 2024 of 107 rigs. Our active rig count in the United States at December 31, 2024 of 103 rigs was less than the rig count of 121 rigs at December 31, 2023, reflecting the industry-wide activity declines due to increased drilling efficiencies and market consolidation. We expect our rig count in the United States will average 106 rigs in the first quarter of 2025. Term contracts help support our operating rig count. Based on contracts in place in the United States as of February 5, 2025, we expect an average of 64 rigs operating under term contracts during the first quarter of 2025 and an average of 40 rigs operating under term contracts during 2025.
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 December 31, 2024 and 2023 was approximately $426 million and $700 million, respectively. Approximately 7.1% of our total contract drilling backlog in the United States at December 31, 2024 is reasonably expected to remain after 2025. See Note 3 of Notes to consolidated financial statements in Item 8 of this Report and “Item 1A. Risk Factors – 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.”
During the fourth quarter of 2024, our completion services segment was impacted by several long-term dedicated customers reducing sequential completion activity after meeting their annual production targets. We expect a seasonal uptick in activity during the first quarter of 2025 as customer budgets reset with the start of the new year.
Activity in our drilling products segment was relatively steady in 2024 compared to the prior year. Drilling products demand is expected to remain steady through the first quarter, given the expectation for a steady U.S. market and continued growth in international markets.
During the fourth quarter, we performed work pursuant to an integrated drilling and completion arrangement that included performance incentives, and we are working to expand customer adoption of these types of arrangements.
Cash capital expenditures for 2024 totaled $678 million. This was an increase from the $616 million of cash capital expenditures in 2023 due to a full year of investing in and maintaining assets related to the NexTier merger and the Ulterra acquisition. The incremental capital spending related to these assets was partially offset by a decrease in business activity in 2024. Additionally, we received proceeds from sale of assets or idle equipment of $25.8 million and $26.5 million in 2024 and 2023, respectively. Based on our current outlook for activity, we expect our capital expenditures for 2025 to be approximately $600 million.
Recent Developments in Joint Ventures and Business Combinations — In December 2024, one of our subsidiaries closed a previously announced joint venture with subsidiaries of ADNOC Drilling and SLB. Our subsidiary holds a 15 percent interest in a newly created company named Turnwell Industries, which has been awarded a contract to drill and complete 144 unconventional wells for ADNOC. In exchange for the minority equity interest, we are providing unconventional drilling and completion expertise to Turnwell, as well as a limited cash contribution to fund our portion of initial working capital.
On September 1, 2023, we completed our merger (the “NexTier merger”) with NexTier Oilfield Solutions Inc. ("NexTier"). Each share of common stock of NexTier issued and outstanding immediately prior to the effective time (including outstanding restricted
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shares) was converted into the right to receive 0.752 shares of our common stock, which based on the closing price of our common stock of $14.91 on September 1, 2023, valued the transaction at approximately $2.8 billion, including the assumption of debt.
On August 14, 2023, we completed our acquisition (the “Ulterra acquisition”) of Ulterra Drilling Technologies, L.P. ("Ulterra"). Total consideration for the acquisition included the issuance of 34.9 million shares of our common stock and payment of approximately $373 million of cash (after purchase price adjustment), which based on the closing price of our common stock of $14.94 on August 14, 2023, valued the transaction at closing at approximately $894 million.
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” included in Part II, Item 7— “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Report.
As of December 31, 2024, we had no borrowings outstanding under our Prior Credit Agreement. We had $2.1 million in letters of credit outstanding under the Prior Credit Agreement at December 31, 2024 and, as a result, had available borrowing capacity of approximately $613 million under the Prior Credit Agreement at that date.
On September 13, 2023, we completed the offering of $400 million in aggregate principal amount of 7.15% Senior Notes due 2033 (the “2033 Notes”). The net proceeds before offering expenses were approximately $396 million, which we used to repay amounts outstanding under our Prior Credit Agreement (as defined below).
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 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 North American oil and natural gas services industry is cyclical and, at times, experiences downturns in demand. During these periods, there has been substantially more oil and natural gas service equipment available than necessary to meet demand. As a result, oil and natural gas service contractors have had difficulty sustaining profit margins and, at times, have incurred losses during the downturn periods. 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. See “Risk Factors” in Item 1A of this Report.
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For the three years ended December 31, 2024, our operating revenues consisted of the following (dollars in thousands):

| 2024 |  | 2023 |  | 2022
Drilling Services | $ | 1,727,810 |  |  | 32.1 | % |  | $ | 1,919,759 |  |  | 46.3 | % |  | $ | 1,544,820 |  |  | 58.3 | %
Completion Services | 3,232,785 |  |  | 60.1 | % |  | 2,017,440 |  |  | 48.7 | % |  | 1,022,413 |  |  | 38.6 | %
Drilling Products | 351,651 |  |  | 6.5 | % |  | 134,679 |  |  | 3.2 | % |  | — |  |  | 0.0 | %
Other | 65,665 |  |  | 1.3 | % |  | 74,578 |  |  | 1.8 | % |  | 80,359 |  |  | 3.1 | %
| $ | 5,377,911 |  |  | 100.0 | % |  | $ | 4,146,456 |  |  | 100.0 | % |  | $ | 2,647,592 |  |  | 100.0 | %

Results of Operations
Effective as of the third quarter of 2023, we revised our reportable segments to align with certain changes in how our Chief Operating Decision Maker (“CODM”) manages and allocates resources to our business as a result of the Ulterra acquisition and NexTier merger. We now have the following reportable business segments: (i) drilling services, (ii) completion services and (iii) drilling products.
Comparison of the years ended December 31, 2023 and 2022
A discussion of our financial condition and results of operations for the fiscal year ended December 31, 2023 compared to the fiscal year ended December 31, 2022 is included in Part II, Item 7— “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the fiscal year ended December 31, 2023, filed with the SEC on February 27, 2024.
Comparison of the years ended December 31, 2024 and 2023
The following tables summarize results of operations by business segment for the years ended December 31, 2024 and 2023:

|  | Year Ended December 31,
Drilling Services (1) |  | 2024 |  | 2023 |  | % Change
|  | (Dollars in thousands)
Revenues |  | $ | 1,727,810 |  |  | $ | 1,919,759 |  |  | (10.0 | %)
Direct operating costs |  | 1,029,591 |  |  | 1,119,200 |  |  | (8.0 | %)
Adjusted gross profit (2) |  | 698,219 |  |  | 800,559 |  |  | (12.8 | %)
Selling, general and administrative |  | 16,502 |  |  | 15,014 |  |  | 9.9 | %
Depreciation, amortization and impairment |  | 477,398 |  |  | 364,312 |  |  | 31.0 | %
Other operating income, net |  | — |  |  | (769) |  |  | (100.0 | %)
Operating income |  | $ | 204,319 |  |  | $ | 422,002 |  |  | (51.6 | %)
Capital expenditures |  | $ | 264,667 |  |  | $ | 334,780 |  |  | (20.9 | %)
Operating days – U.S. (3) |  | 40,899 |  | 45,270 |  | (9.7 | %)
Average revenue per operating day – U.S. (3) |  | $ | 35.86 |  |  | $ | 36.24 |  |  | (1.0 | %)
Average direct operating costs per operating day – U.S. (3) |  | $ | 19.80 |  |  | $ | 19.42 |  |  | 2.0 | %
Average adjusted gross profit per operating day – U.S. (3) |  | $ | 16.06 |  |  | $ | 16.83 |  |  | (4.6 | %)

(1)Drilling services segment represents our contract drilling, directional drilling, oilfield technology and electrical controls and automation businesses.
(2)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.
(3)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.
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Total revenues and direct operating costs decreased primarily due to a decrease in operating days in our contract drilling business within the United States. Average revenue per operating day remained relatively flat while average direct operating costs per operating day increased slightly. The decline in operating days impacted the fixed cost leverage for U.S. drilling rigs.
The decrease in operating days for our U.S. contract drilling business reflects the industry-wide activity declines due to increased drilling efficiencies and market consolidation.
Depreciation, amortization and impairment expense increased primarily due to a charge of $114 million related to the abandonment of 42 legacy, non-Tier-1 super-spec drilling rigs and related equipment. See Note 6 of Notes to consolidated financial statements for additional information.
Capital expenditures decreased primarily due to reduced investment in our ancillary drilling services not included within our contract drilling business and timing of order placement.

|  | Year Ended December 31,
Completion Services (1) |  | 2024 |  | 2023 |  | % Change
|  | (Dollars in thousands)
Revenues |  | $ | 3,232,785 |  |  | $ | 2,017,440 |  |  | 60.2 | %
Direct operating costs |  | 2,658,170 |  |  | 1,567,940 |  |  | 69.5 | %
Adjusted gross profit (2) |  | 574,615 |  |  | 449,500 |  |  | 27.8 | %
Selling, general and administrative |  | 41,557 |  |  | 26,050 |  |  | 59.5 | %
Depreciation, amortization and impairment |  | 564,155 |  |  | 283,230 |  |  | 99.2 | %
Impairment of goodwill |  | 885,240 |  |  | — |  |  | NA
Other operating income, net |  | (17,792) |  |  | — |  |  | NA
Operating income (loss) |  | $ | (898,545) |  |  | $ | 140,220 |  |  | (740.8 | %)
Capital expenditures |  | $ | 320,329 |  |  | $ | 214,746 |  |  | 49.2 | %

(1)Completion services represents the combination of well completion business from the NexTier merger and our legacy pressure pumping business.
(2)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.
The changes in the results of our completion services segment for the year ended December 31, 2024 as compared to December 31, 2023 can be primarily attributed to the NexTier merger, which closed on September 1, 2023. The NexTier merger had a material impact on our reported results of operations. The results for the year ended December 31, 2024 represent the combination of the well completion business from the NexTier merger and our legacy pressure pumping business. Due to the full integration of our legacy pressure pumping business into the NexTier legal entity in the first quarter of 2024, we are unable to provide a meaningful year-over-year comparison excluding the impact of the NexTier merger.
During the year ended December 31, 2024, we recorded an $885 million impairment charge to goodwill associated with our completion services reporting unit. See Note 7 of Notes to consolidated financial statements for additional information.
Other operating income, net in 2024 was due to gain on legal settlements.
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|  | Year Ended December 31,
Drilling Products |  | 2024 |  | 2023 |  | % Change
|  | (Dollars in thousands)
Revenues |  | $ | 351,651 |  |  | $ | 134,679 |  |  | 161.1 | %
Direct operating costs |  | 191,107 |  |  | 81,555 |  |  | 134.3 | %
Adjusted gross profit (1) |  | 160,544 |  |  | 53,124 |  |  | 202.2 | %
Selling, general and administrative |  | 35,860 |  |  | 11,158 |  |  | 221.4 | %
Depreciation, amortization and impairment |  | 100,610 |  |  | 48,467 |  |  | 107.6 | %
Operating income (loss) |  | $ | 24,074 |  |  | $ | (6,501) |  |  | (470.3) | %
Capital expenditures |  | $ | 61,687 |  |  | $ | 24,572 |  |  | 151.0 | %

(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.
The changes in the results of our drilling products segment for the year ended December 31, 2024 as compared to December 31, 2023 are attributable to the Ulterra acquisition, which closed on August 14, 2023. As such, there was no meaningful year-over-year comparison.
Direct operating costs and depreciation, amortization and impairment expense were approximately $7.9 million and $17.7 million higher than they would have otherwise been for the year ended December 31, 2024, respectively, as a result of the step up to fair value of our drill bits in accordance with purchase accounting. Direct operating costs and depreciation, amortization and impairment expense were approximately $11.0 million and $18.0 million higher than they would have otherwise been for the year ended December 31, 2023, respectively, as a result of the step up to fair value of our drill bits in accordance with purchase accounting.

|  | Year Ended December 31,
Other |  | 2024 |  | 2023 |  | % Change
|  | (Dollars in thousands)
Revenues |  | $ | 65,665 |  |  | $ | 74,578 |  |  | (12.0) | %
Direct operating costs |  | 41,001 |  |  | 42,624 |  |  | (3.8 | %)
Adjusted gross profit (1) |  | 24,664 |  |  | 31,954 |  |  | (22.8) | %
Selling, general and administrative |  | 708 |  |  | 888 |  |  | (20.3 | %)
Depreciation, depletion, amortization and impairment |  | 24,043 |  |  | 28,237 |  |  | (14.9 | %)
Operating income (loss) |  | $ | (87) |  |  | $ | 2,829 |  |  | (103.1 | %)
Capital expenditures |  | $ | 21,813 |  |  | $ | 24,645 |  |  | (11.5) | %

(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.
Revenue decreased due to a lower volume of services provided by our oilfield rentals business.
Depreciation, depletion, amortization and impairment expense decreased primarily due to a $7.0 million impairment recorded in our oil and natural gas business in 2023 compared to a $3.8 million impairment in 2024.
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|  | Year Ended December 31,
Corporate |  | 2024 |  | 2023 |  | % Change
|  | (Dollars in thousands)
Selling, general and administrative |  | $ | 173,710 |  |  | $ | 116,852 |  |  | 48.7 | %
Merger and integration expense |  | $ | 33,037 |  |  | $ | 98,077 |  |  | (66.3 | %)
Depreciation |  | $ | 5,667 |  |  | $ | 7,170 |  |  | (21.0 | %)
Other operating (income) expense, net |  | $ | 7,084 |  |  | $ | (15,503) |  |  | (145.7 | %)
Interest income |  | $ | (5,729) |  |  | $ | (6,122) |  |  | (6.4 | %)
Interest expense, net of amount capitalized |  | $ | 71,963 |  |  | $ | 52,870 |  |  | 36.1 | %
Other (income) expense |  | $ | 975 |  |  | $ | (1,898) |  |  | (151.4 | %)
Capital expenditures |  | $ | 9,890 |  |  | $ | 16,947 |  |  | (41.6 | %)

Selling, general and administrative expense increased primarily due to the reorganization of acquired Ulterra and NexTier support personnel to corporate following the NexTier merger and the Ulterra acquisition.
Merger and integration expense decreased due to the timing of the NexTier merger and the Ulterra acquisition, which both closed in the third quarter of 2023.
The $22.6 million change in other operating income, net was primarily due to a $5.2 million favorable legal settlement and a $6.5 million reversal of cumulative compensation costs associated with certain performance-based restricted stock units in 2023. Additionally, there was a $5.8 million credit loss expense in 2024 due to a deterioration in the financial condition of a customer.
Interest expense increased primarily due to the offering of 2033 Notes in the third quarter of 2023. See Note 9 of Notes to consolidated financial statements for additional information on our long-term debt.
The decrease in capital expenditures was primarily due to the purchase of an aircraft in 2023.
Income Taxes
The effective tax rate decreased to (1.0)% for 2024 compared to 19.9% for 2023. Our effective income tax rate fluctuates based on, among other factors, changes in pre-tax income in countries with varying statutory tax rates, changes in valuation allowances, and the impacts of various other permanent adjustments. The impact of goodwill impairments that are not deductible for income tax had a significant impact on our effective tax rate for the year ended December 31, 2024.
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 revolving credit facility and cash provided by operating activities. As of December 31, 2024, we had approximately $453 million in working capital, including $239 million of cash and cash equivalents, and approximately $613 million available under the Prior 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.
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.
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Loans under the Credit Agreement bear interest by reference, at our election, to the SOFR rate (in addition to 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. 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 0.150% to 0.350% 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 the covenants under the Prior Credit Agreement at December 31, 2024.
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 December 31, 2024, 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 $42.9 million of outstanding letters of credit at December 31, 2024, which was comprised of $38.8 million outstanding under the Reimbursement Agreement, $2.1 million outstanding under the Prior 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 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 December 31, 2024, no amounts had been drawn under the letters of credit.
Our outstanding long-term debt at December 31, 2024 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 $6.4 million of Equipment Loans. We were in compliance with all covenants under the associated agreements and indentures at December 31, 2024.
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For a full description of the Prior Credit Agreement, the Reimbursement Agreement, the 2028 Notes, the 2029 Notes, and the 2033 Notes, see Note 9 of Notes to consolidated financial statements included as a part of Item 8 of this Report.
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.
A portion of our capital expenditures can be adjusted and managed by us to match market demand and activity levels. Based on our current outlook for activity, we expect our capital expenditures for 2025 to be approximately $600 million. The majority of these expenditures are expected to be used for normal, recurring items necessary to support our business.
We anticipate $52.2 million of expenditures in 2025 related to various contractual obligations such as certain commitments to purchase proppants and lease liabilities.
As of December 31, 2024, we had working capital of $453 million, including cash, cash equivalents and restricted cash of $241 million, compared to working capital of $435 million, including cash, cash equivalents and restricted cash of $193 million, at December 31, 2023.
During 2024, our sources of cash flow included:
•$1.2 billion from operating activities, and
•$25.8 million in proceeds from the disposal of property and equipment.
During 2024, our uses of cash flow included:
•$678 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, oilfield rentals and manufacturing operations and to fund investments in oil and natural gas properties on a non-operating working interest basis,
•$290 million for repurchases of our common stock,
•$127 million to pay dividends on our common stock,
•$45.5 million for payments related to finance leases, and
•$17.5 million for other investing and financing activities.
We paid cash dividends during the year ended December 31, 2024 as follows:

| Per Share |  | Total
|  |  | (in thousands)
Paid on March 15, 2024 | $ | 0.08 |  |  | $ | 32,553 |
Paid on June 17, 2024 | 0.08 |  |  | 31,815 |
Paid on September 16, 2024 | 0.08 |  |  | 31,225 |
Paid on December 16, 2024 | 0.08 |  |  | 31,198 |
Total cash dividends | $ | 0.32 |  |  | $ | 126,791 |

On February 5, 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 March 17, 2025 to holders of record as of March 3, 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.
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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 December 31, 2024, we had remaining authorization to purchase approximately $759 million of our outstanding common stock under the stock buyback program. Shares of stock purchased under the buyback program are held as treasury shares.
We acquired shares of stock from employees during 2024, 2023 and 2022 that are accounted for as treasury stock. Certain of these shares were acquired to satisfy the exercise price and employees’ tax withholding obligations upon the exercise of stock options. The remainder of these shares were acquired to satisfy payroll withholding obligations upon the settlement of performance unit awards and the vesting of restricted stock units. These shares were acquired at fair market value. These acquisitions were made pursuant to the terms of the Patterson-UTI Energy, Inc. Amended and Restated 2014 Long-Term Incentive Plan, as amended (the “2014 Plan”), the Patterson-UTI Energy, Inc. 2021 Long-Term Incentive Plan (the “2021 Plan”), the NexTier Oilfield Solutions Inc. Equity and Incentive Award Plan and the NexTier Oilfield Solutions Inc. (Former C&J Energy) Management Incentive Plan, and not pursuant to the stock buyback program.
Treasury stock acquisitions during the years ended December 31, 2024, 2023 and 2022 were as follows (dollars in thousands):

| 2024 |  | 2023 |  | 2022
| Shares |  | Cost |  | Shares |  | Cost |  | Shares |  | Cost
Treasury shares at beginning of period | 105,580,011 |  | $ | 1,657,675 |  |  | 88,758,722 |  | $ | 1,453,079 |  |  | 84,128,995 |  | $ | 1,372,641 |
Purchases pursuant to stock buyback program | 26,646,698 |  | 280,327 |  |  | 14,086,229 |  | 168,631 |  |  | 3,254,599 |  | 57,173 |
Acquisitions pursuant to long-term incentive plan | 1,213,319 |  | 13,065 |  |  | 2,735,060 |  | 35,965 |  |  | 1,372,101 |  | 23,237 |
Other | — |  | — |  |  | — |  | — |  |  | 3,027 |  | 28 |
Treasury shares at end of period | 133,440,028 |  | $ | 1,951,067 |  |  | 105,580,011 |  | $ | 1,657,675 |  |  | 88,758,722 |  | $ | 1,453,079 |

As of December 31, 2024, we had unrecognized compensation costs of $42.8 million and $12.8 million related to our unvested restricted stock units and our unvested Performance Units, respectively. The weighted-average remaining vesting periods for these awards were 1.71 years and 1.04 years, respectively as of December 31, 2024. See Note 12 of Notes to consolidated financial statements in Item 8 of this Report for additional discussion regarding our stock-based compensation.
Commitments — As of December 31, 2024, we had commitments to purchase major equipment totaling approximately $65.9 million.
Our completion services segment has entered into agreements to purchase minimum quantities of proppants from certain vendors. As of December 31, 2024, the remaining minimum obligation under these agreements was approximately $19.8 million, of which approximately, $17.4 million and $2.4 million relate to 2025 and 2026, respectively.
See Note 10 of Notes to consolidated financial statements in Item 8 of this Report for additional information on our current commitments and contingencies as of December 31, 2024.
Operating lease liabilities totaled $47.6 million and finance lease liabilities totaled $25.4 million at December 31, 2024. See Note 13 of Notes to consolidated financial statements in Item 8 of this Report for additional information on our operating and finance leases as of December 31, 2024.
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.
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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 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. Accounting estimates and assumptions discussed in this section are those considered to be the most critical to an understanding of our financial statements because they involve significant judgments and uncertainties. We believe the following critical accounting estimates used in preparing our consolidated financial statements address all important areas where the nature of the estimates or assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change. For additional information on our accounting policies, see Note 1 of Notes to consolidated financial statements included as a part of Item 8 of this Report.
Depreciation and amortization — Our industry is very capital intensive, as property and equipment represented 51.6% of our total assets as of December 31, 2024 and depreciation, depletion, amortization and impairment represented 18.7% of our total operating costs and expenses in 2024. Our property and equipment is carried at cost less accumulated depreciation and amortization. No provision for salvage value is considered in determining depreciation of our property and equipment. We calculate depreciation and amortization on our assets based on the estimated useful lives that we believe are reasonable. The estimated useful lives are subject to key assumptions such as maintenance, utilization and job variation. These estimates may change due to a number of factors such as changes in operating conditions or advances in technology. The method of depreciation does not change whenever equipment becomes idle. Maintenance and repairs are charged to expense when incurred. Renewals and betterments which extend the life or improve existing property and equipment are capitalized.
The following table outlines a 10% change in the useful lives on our major categories of property and equipment and the impact on operating income for the year ended December 31, 2024:

| Useful Lives | Change | Impact (in thousands)
Drilling services equipment | 1-15 years | 10% | $ | 54,444 |
Completion services equipment | 1-25 years | 10% | 46,973 |
|  |  | $ | 101,417 |

Impairment of long-lived assets — 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 respective asset or the primary asset in an asset group. These estimates of cash flows are based on historical trends in the industry as well as our expectations regarding the continuation of these trends in the future. As of December 31, 2024, no impairment was indicated for our long-lived tangible or definite-lived intangible assets. See Note 6 of Notes to consolidated financial statements included as a part of Item 8 of this Report.
While we believe our judgments and assumptions are reasonable, geopolitical instability, global or regional decreases in the demand of our services and products, or other unforeseen macroeconomic considerations could negatively impact the expected cash flows used in our recoverability tests on 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.
Fair values of assets acquired and liabilities assumed in acquisitions — Assets acquired and liabilities assumed in a business combination are recorded at their estimated fair values on the date of acquisition. The difference between the purchase price amount and the net fair value of assets acquired and liabilities assumed is recognized as goodwill on the balance sheet if the purchase price exceeds the estimated net fair value or as a bargain purchase gain on the income statement if the purchase price is less than the estimated net fair value. We apply significant judgment in estimating the fair value of assets acquired and liabilities assumed, which involves the use of significant estimates and assumptions with respect to rig counts, cash flow projections, estimated economic useful lives, operating and capital cost estimates, customer attrition rates, contributory asset charges, royalty rates and discount rates. Changes in these judgments or estimates can have a material impact on the valuation of the respective assets and liabilities acquired and our results of operations in periods after acquisition, such as through depreciation and amortization expense. The allocation of the purchase price may be modified up to one year after the acquisition date as more information is obtained about the fair value of assets acquired and liabilities assumed. See Note 2 of Notes to consolidated financial statements included as a part of Item 8 of this Report.
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Goodwill — We assess goodwill 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 the Ulterra acquisition was allocated to that reporting unit. We determined our completion services operating segment consists of two reporting units; completion services, which is primarily comprised of our hydraulic fracturing operations and other integrated service offerings, and cementing services.
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 have led to our reduced outlook for activity. During the third quarter of 2024, we viewed the reduction in activity forecasts combined with the recent decline in the market price of our common stock as a triggering event that warranted a quantitative assessment for goodwill impairment.
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.
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.
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 will persist 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.
Based on the results of the goodwill impairment tests performed during the third quarter of 2024, the fair values of the drilling products and cementing services reporting units exceeded their carrying values by approximately 13% and 73%, respectively. Accordingly, no impairment was recorded for the drilling products and cementing services reporting units.
Assuming all changes are isolated, a decrease of 100 bps in our long-term revenue growth rate for our drilling products reporting unit would reduce our estimated fair value by approximately 5%, while a 100 bps increase to our discount rate would reduce our estimated fair value by approximately 10%.
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.
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Accruals for self-insured levels of insurance coverage — We maintain insurance coverage for fire, windstorm and other risks of physical loss to our equipment and certain other assets, employers’ liability, automobile liability, commercial general liability, workers’ compensation and insurance for other specific risks. We also self-insure a number of other risks, including loss of earnings and business interruption and most of our cybersecurity risks, and do not carry a significant amount of insurance to cover risks of underground reservoir damage. Our insurance accruals are based on claims filed and estimates of claims incurred but not reported and are developed by our management with assistance from our third-party actuary and third-party claims administrator. The insurance accruals are influenced by our past claims experience factors and by published industry development factors. If we experience insurance claims or costs above or below our historically evaluated levels, our estimates could be materially affected. The frequency and number of claims or incidents could vary significantly over time, which could materially affect our self-insurance liabilities. Additionally, the actual costs to settle the self-insurance liabilities could materially differ from the original estimates and cause us to incur additional costs in future periods associated with prior year claims. A sensitivity analysis of the impact on earnings for these periods if other assumptions had been used in recording these liabilities is not practicable given the number of underlying assumptions and the wide range of reasonably possible outcomes. See “Item 1A. Risk Factors – Our operations are subject to a number of operational risks, including environmental and weather risks, which could expose us to significant losses and damage claims. We are not fully insured against all of these risks and our contractual indemnity provisions may not fully protect us.”
Income taxes — We are subject to income taxes in the United States and other foreign jurisdictions. We compute our provision for income taxes using the asset and liability method, under which deferred tax assets and liabilities are recognized for operating loss and tax credit carryforwards and for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the results of operations in the period that includes the enactment date. In assessing the realizability of our deferred tax assets, if it is more likely than not that a portion of the deferred tax assets will not be realized in a future period, the deferred tax assets will be reduced by a valuation allowance. We believe the valuation allowance is a critical accounting estimate because it is susceptible to change from period to period, requires assumptions about our future income over the lives of the deferred tax assets, and because the impact of increasing or decreasing the valuation allowance is potentially material to our results of operations.
Our methodology for recording income taxes requires a significant amount of judgment in the use of assumptions and estimates. Additionally, we forecast certain tax elements, such as future taxable income, as well as evaluate the feasibility of implementing tax planning strategies. Given the inherent uncertainty involved with the use of such variables, there can be significant variation between anticipated and actual results. Unforeseen events may significantly impact these variables, and changes to these variables could have a material impact on our income tax accounts. The final determination of our income tax liabilities involves the interpretation of local tax laws and related authorities in each jurisdiction. Changes in the operating environments, including changes in tax law, could impact the determination of our income tax liabilities for a tax year.
We continue to monitor income tax developments, including OECD Pillar 2 legislation, in the United States and other countries where we have legal entities. We recognize tax benefits related to uncertain tax positions when, in our judgment, it is more likely than not that such positions will be sustained on examination, including resolutions of any related appeals or litigation, based on the technical merits. We adjust our liabilities for uncertain tax positions when our judgment changes as a result of new information previously unavailable. We routinely monitor the potential impact of these situations. As of December 31, 2024, we have no unrecognized tax benefits.
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 have been relatively range-bound since the end of 2022. The current demand for equipment and services remains impacted by macro conditions, including commodity prices, geopolitical environment, 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. Oil prices averaged $70.73 per barrel in the fourth quarter of 2024. Natural gas prices (based on the Henry Hub Spot Market Price) averaged $2.45 per MMBtu in the fourth quarter of 2024.
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
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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
Inflation rates have begun to moderate. However, we continue to actively monitor market trends primarily related to sourcing labor, supplies and equipment.
Recently Issued Accounting Standards
For a discussion of recently issued accounting standards, see Note 1 of Notes to consolidated financial statements included as a part of Item 8 of this Report.
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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 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).

| Year Ended December 31,
| 2024 |  | 2023 |  | 2022
| (in thousands)
Net income (loss) | $ | (966,399) |  |  | $ | 245,952 |  |  | $ | 154,658 |
Income tax expense (benefit) | 9,453 |  |  | 61,152 |  |  | 13,204 |
Net interest expense | 66,234 |  |  | 46,748 |  |  | 39,896 |
Depreciation, depletion, amortization and impairment | 1,171,873 |  |  | 731,416 |  |  | 483,945 |
Impairment of goodwill | 885,240 |  |  | — |  |  | — |
Merger and integration expense | 33,037 |  |  | 98,077 |  |  | 2,069 |
Adjusted EBITDA | $ | 1,199,438 |  |  | $ | 1,183,345 |  |  | $ | 693,772 |

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Adjusted Gross Profit
We define “Adjusted gross profit” as revenues less direct operating costs (excluding depreciation, depletion, amortization and impairment expense, which does not include impairment of goodwill). 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 year ended December 31, 2024 |  |  |  |  |  |  |
Revenues | $ | 1,727,810 |  |  | $ | 3,232,785 |  |  | $ | 351,651 |  |  | $ | 65,665 |
Less direct operating costs | (1,029,591) |  |  | (2,658,170) |  |  | (191,107) |  |  | (41,001) |
Less depreciation, depletion, amortization and impairment | (477,398) |  |  | (564,155) |  |  | (100,610) |  |  | (24,043) |
GAAP gross profit | 220,821 |  |  | 10,460 |  |  | 59,934 |  |  | 621 |
Depreciation, depletion, amortization and impairment | 477,398 |  |  | 564,155 |  |  | 100,610 |  |  | 24,043 |
Adjusted gross profit | $ | 698,219 |  |  | $ | 574,615 |  |  | $ | 160,544 |  |  | $ | 24,664 |
For the year ended December 31, 2023 |  |  |  |  |  |  |
Revenues | $ | 1,919,759 |  |  | $ | 2,017,440 |  |  | $ | 134,679 |  |  | $ | 74,578 |
Less direct operating costs | (1,119,200) |  |  | (1,567,940) |  |  | (81,555) |  |  | (42,624) |
Less depreciation, depletion, amortization and impairment | (364,312) |  |  | (283,230) |  |  | (48,467) |  |  | (28,237) |
GAAP gross profit | 436,247 |  |  | 166,270 |  |  | 4,657 |  |  | 3,717 |
Depreciation, depletion, amortization and impairment | 364,312 |  |  | 283,230 |  |  | 48,467 |  |  | 28,237 |
Adjusted gross profit | $ | 800,559 |  |  | $ | 449,500 |  |  | $ | 53,124 |  |  | $ | 31,954 |
For the year ended December 31, 2022 |  |  |  |  |  |  |
Revenues | $ | 1,544,820 |  |  | $ | 1,022,413 |  |  | $ | — |  |  | $ | 80,359 |
Less direct operating costs | (1,025,904) |  |  | (781,385) |  |  | — |  |  | (39,261) |
Less depreciation, depletion, amortization and impairment | (354,116) |  |  | (98,162) |  |  | — |  |  | (26,496) |
GAAP gross profit | 164,800 |  |  | 142,866 |  |  | — |  |  | 14,602 |
Depreciation, depletion, amortization and impairment | 354,116 |  |  | 98,162 |  |  | — |  |  | 26,496 |
Adjusted gross profit | $ | 518,916 |  |  | $ | 241,028 |  |  | $ | — |  |  | $ | 41,098 |

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk
As of December 31, 2024, we would have had exposure to interest rate market risk associated with any outstanding borrowings and letters of credit that we had under the Prior Credit Agreement and amounts owed under the Reimbursement Agreement.
Loans under the Prior Credit Agreement bore interest by reference, at our election, to the SOFR rate (subject to a 0.10% per annum adjustment) or base rate, in each case subject to a 0% floor. The applicable margin on SOFR rate loans varied from 1.00% to 2.00% and the applicable margin on base rate loans varied from 0% to 1.00%, in each case determined based on our credit rating. As of December 31, 2024, 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 was 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 varied from 0.10% to 0.30% based on our credit rating. As of December 31, 2024, we had $2.1 million in letters of credit outstanding and, as a result, had available borrowing capacity of approximately $613 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.
Some 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, some 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.
Item 8. Financial Statements and Supplementary Data.
Financial Statements are filed as a part of this Report at the end of Part IV hereof beginning at page F-1, Index to Consolidated Financial Statements, and are incorporated herein by this reference.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures.
Disclosure Controls and Procedures:
Under the supervision and with the participation of our management, including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), we conducted an evaluation of the effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Exchange Act, as of the end of the period covered by this Report. Based on this evaluation, our CEO and CFO concluded that, as of December 31, 2024, our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and is accumulated and reported to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.
Management’s Report on Internal Control over Financial Reporting:
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including our CEO and CFO, we carried out an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2024, based on the Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, our management has concluded that our internal control over financial reporting was effective as of December 31, 2024.
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The effectiveness of our internal control over financial reporting as of December 31, 2024 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on page F-2 of this Report and which is incorporated by reference into Item 8 of this Report.
Changes in Internal Control over Financial Reporting:
There have been no changes to our internal control over financial reporting during the most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information.
(c)During the three months ended December 31, 2024, 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 |  | Number of Shares to be Sold |  |
Name and Title |  | Action |  | Date |  | Rule 10b5-1 |  | Non-Rule 10b5-1 |  |  | Expiration
Robert Drummond Jr., | Director |  | Termination |  | November 8, 2024 |  | X |  |  |  | 1,250,000 |  | Plan terminated November 8, 2024

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections.
None.
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PART III
Certain information required by Part III is omitted from this Report because we expect to file a definitive proxy statement (the “Proxy Statement”) pursuant to Regulation 14A of the Securities Exchange Act of 1934 no later than 120 days after the end of the fiscal year covered by this Report and certain information included therein is incorporated herein by reference.
Item 10. Directors, Executive Officers and Corporate Governance.
The information required by this Item is incorporated herein by reference to the Proxy Statement.
We have adopted a Code of Business Conduct and Ethics for Senior Financial Executives, which covers, among others, our principal executive officer and principal financial and accounting officer. The text of this code is located on our website under “Corporate Governance.” Our Internet address is www.patenergy.com. We intend to disclose any amendments to or waivers from this code on our website within four business days following the date of the amendment or waiver.
Item 11. Executive Compensation.
The information required by this Item is incorporated herein by reference to the Proxy Statement.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The information required by this Item is incorporated herein by reference to the Proxy Statement.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
The information required by this Item is incorporated herein by reference to the Proxy Statement.
Item 14. Principal Accounting Fees and Services.
The information required by this Item is incorporated herein by reference to the Proxy Statement.
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PART IV
Item 15. Exhibits and Financial Statement Schedule.
(a)(1)Financial Statements
See Index to Consolidated Financial Statements on page F-1 of this Report.
(a)(2)Report of Independent Registered Public Accounting Firm
The report of our independent registered public accounting firm (PCAOB ID: 238) with respect to the above-referenced financial statements and their report on internal control over financial reporting are included on page F-2 of this Report.
(a)(3)Financial Statement Schedule
Schedule II — Valuation and qualifying accounts is filed herewith on page S-1.
All other financial statement schedules have been omitted because they are not applicable or the information required therein is included elsewhere in the financial statements or notes thereto.
(a)(3)Exhibits
The following exhibits are filed herewith or incorporated by reference herein. Our Commission file number is 0-22664.

2.1 |  | Agreement and Plan of Merger, dated as of June 14, 2023, by and among Patterson-UTI Energy, Inc., Pecos Merger Sub Inc., Pecos Second Merger Sub LLC and NexTier Oilfield Solutions Inc. (filed June 15, 2023 as Exhibit 2.1 to our Current Report on Form 8-K and incorporated herein by reference).
2.2 |  | First Amendment to Agreement and Plan of Merger, dated July 27, 2023, by and between Patterson-UTI and NexTier Oilfield Solutions Inc. (filed July 28, 2023 as Exhibit 2.1 to our Current Report on Form 8-K and incorporated herein by reference).
2.3 |  | Agreement and Plan of Merger, dated as of July 3, 2023, by and among Patterson-UTI Energy, Inc., PJ Merger Sub Inc., PJ Second Merger Sub LLC, BEP Diamond Holdings Corp. and BEP Diamond Topco L.P. (filed July 5, 2023 as Exhibit 2.1 to our Current Report on Form 8-K and incorporated herein by reference).
3.1 |  | Restated Certificate of Incorporation (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 (filed June 15, 2023 as Exhibit 3.1 to our Current Report on Form 8-K and incorporated herein by reference).
4.1 |  | Description of Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934 (filed February 27, 2024 as Exhibit 4.1 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2023 and incorporated herein by reference).
4.2 |  | Registration Rights Agreement with Bear, Stearns and Co. Inc., dated March 25, 1994, as assigned to REMY Capital Partners III, L.P. (filed March 19, 2002 as Exhibit 4.3 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2001 and incorporated herein by reference).
4.3 |  | Base Indenture, dated January 19, 2018, among Patterson-UTI Energy, Inc., the several guarantors named therein and Wells Fargo Bank, National Association, as trustee (filed January 19, 2018 as Exhibit 4.1 to our Current Report on Form 8-K and incorporated herein by reference).
4.4 |  | First Supplemental Indenture, dated January 19, 2018, among Patterson-UTI Energy, Inc., the several guarantors named therein and Wells Fargo Bank, National Association, as trustee (filed January 19, 2018 as Exhibit 4.2 to our Current Report on Form 8-K and incorporated herein by reference).

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4.5 |  | Form of 3.95% Senior Note due 2028 (included in Exhibit 4.4 above).
4.6 |  | Base Indenture, dated November 15, 2019, between Patterson-UTI Energy, Inc. and U.S. Bank National Association, as trustee (filed November 15, 2019 as Exhibit 4.1 to our Current Report on Form 8-K and incorporated herein by reference).
4.7 |  | First Supplemental Indenture, dated November 15, 2019, between Patterson-UTI Energy, Inc. and U.S. Bank National Association, as trustee (filed November 15, 2019 as Exhibit 4.2 to our Current Report on Form 8-K and incorporated herein by reference).
4.8 |  | Form of 5.15% Senior Note due 2029 (included in Exhibit 4.7 above).
4.9 |  | Second Supplemental Indenture, dated September 13, 2023, between Patterson-UTI Energy, Inc. and U.S. Bank Trust Company, National Association, as trustee (filed September 13, 2023 as Exhibit 4.1 to our Current Report on Form 8-K and incorporated herein by reference).
4.10 |  | Form of 7.15% Senior Notes due 2033 (included in Exhibit 4.9 above).
10.1 |  | Patterson-UTI Energy, Inc. 2014 Long-Term Incentive Plan, as amended and restated and further amended effective June 6, 2019 (filed June 6, 2019 as Exhibit 10.1 to our Current Report on Form 8-K and incorporated herein by reference).*
10.2 |  | Patterson-UTI Energy, Inc. 2021 Long-Term Incentive Plan, as amended through June 6, 2024 (filed June 6, 2024 as Exhibit 99.1 to our Registration Statement on Form S-8 and incorporated herein by reference).*
10.3 |  | NexTier Oilfield Solutions Inc. (Former C&J Energy) Management Incentive Plan, as amended September 1, 2023 (filed September 1, 2023 as Exhibit 10.4 to our Current Report on Form 8-K and incorporated herein by reference).*
10.4 |  | NexTier Oilfield Solutions Inc. Equity and Incentive Award Plan, as amended September 1, 2023 (filed September 1, 2023 as Exhibit 10.3 to our Current Report on Form 8-K and incorporated herein by reference).*
10.5 |  | Form of Executive Officer Restricted Stock Unit Award Agreement (filed August 3, 2021 as Exhibit 10.2 to our Quarterly Report on Form 10-Q and incorporated herein by reference).*
10.6 |  | Form of Executive Officer Stock Option Agreement (filed April 21, 2014 as Exhibit 10.4 to our Current Report on Form 8-K and incorporated herein by reference).*
10.7 |  | Form of Non-Employee Director Stock Option Agreement (filed April 21, 2014 as Exhibit 10.6 to our Current Report on Form 8-K and incorporated herein by reference).*
10.8 |  | Form of Non-Employee Director Restricted Stock Unit Award Agreement.*+
10.9 |  | Form of Executive Officer Share-Settled Performance Share Award Agreement (filed August 3, 2021 as Exhibit 10.3 to our Quarterly Report on Form 10-Q and incorporated herein by reference).*
10.10 |  | Form of Executive Officer Share-Settled Performance Share Award Agreement (filed July 29, 2024 as Exhibit 10.2 to our Quarterly Report on Form 10-Q and incorporated herein by reference).*
10.11 |  | Patterson-UTI Energy, Inc. Qualified Retiree Program (filed July 29, 2024 as Exhibit 10.3 to our Quarterly Report on Form 10-Q and incorporated herein by reference).*
10.12 |  | Form of Letter Agreement regarding termination, effective as of January 29, 2004, entered into by Patterson-UTI Energy, Inc. with Kenneth N. Berns (filed on February 25, 2005 as Exhibit 10.23 to our Annual Report on Form 10-K for the year ended December 31, 2004 and incorporated herein by reference).*

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10.13 |  | Employment Agreement, dated as of January 1, 2023, by and between Patterson-UTI Energy, Inc. and James M. Holcomb (filed on January 3, 2023 as Exhibit 10.1 to our Current Report on Form 8-K and incorporated herein by reference).*
10.14 |  | Letter Agreement, dated August 30, 2023, by and between Patterson-UTI Energy, Inc. and James M. Holcomb (filed September 1, 2023 as Exhibit 10.7 to our Current Report on Form 8-K and incorporated herein by reference).*
10.15 |  | Letter Agreement, dated August 27, 2024, by and between Patterson-UTI Energy, Inc. and James M. Holcomb (filed September 3, 2024 as Exhibit 10.1 to our Current Report on Form 8-K and incorporated herein by reference).*
10.16 |  | Employment Agreement, effective as of August 1, 2016, by and between Patterson-UTI Energy, Inc. and William Andrew Hendricks, Jr. (filed August 2, 2016 as Exhibit 10.2 to our Quarterly Report on Form 10-Q and incorporated herein by reference).*
10.17 |  | First Amendment to Employment Agreement, effective as April 9, 2021, by and between Patterson-UTI Energy, Inc. and William Andrew Hendricks, Jr. (filed August 3, 2021 as Exhibit 10.4 to our Quarterly Report on Form 10-Q and incorporated herein by reference).*
10.18 |  | Employment Agreement, effective as of August 1, 2016, by and between Patterson-UTI Energy, Inc. and Seth D. Wexler (filed February 13, 2017 as Exhibit 10.20 to our Annual Report on Form 10-K for the year ended December 31, 2016 and incorporated herein by reference).*
10.19 |  | First Amendment to Employment Agreement, effective as April 9, 2021, by and between Patterson-UTI Energy, Inc. and Seth D. Wexler (filed August 3, 2021 as Exhibit 10.6 to our Quarterly Report on Form 10-Q and incorporated herein by reference).*
10.20 |  | Employment Agreement, dated as of September 3, 2017, between Patterson-UTI Energy, Inc. and C. Andrew Smith (filed September 8, 2017 as Exhibit 10.2 to our Current Report on Form 8-K and incorporated herein by reference).*
10.21 |  | First Amendment to Employment Agreement, effective as April 9, 2021, by and between Patterson-UTI Energy, Inc. and C. Andrew Smith (filed August 3, 2021 as Exhibit 10.5 to our Quarterly Report on Form 10-Q and incorporated herein by reference).*
10.22 |  | Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Kenneth N. Berns (filed on February 4, 2004 as Exhibit 10.5 to our Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).*
10.23 |  | First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and Kenneth N. Berns, entered into November 1, 2007 (filed November 5, 2007 as Exhibit 10.11 to our Quarterly Report on Form 10-Q and incorporated herein by reference).*
10.24 |  | Separation Agreement and General Release of Claims, dated September 1, 2023, by and between NexTier Oilfield Solutions Inc. and Robert W. Drummond (filed September 1, 2023 as Exhibit 10.6 to our Current Report on Form 8-K and incorporated herein by reference).*
10.25 |  | Form of Indemnification Agreement entered into by Patterson-UTI Energy, Inc. with each of its directors and executive officers (filed April 28, 2004 as Exhibit 10.11 to our Annual Report on Form 10-K, as amended, for the year ended December 31, 2003 and incorporated herein by reference).*
10.26 |  | Amended and Restated Credit Agreement dated March 27, 2018 among Patterson-UTI Energy, Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent, letter of credit issuer, swing line lender and lender and each of the other letter of credit issuers and lenders party thereto (filed March 27, 2018 as Exhibit 10.1 to our Current Report on Form 8-K and incorporated herein by reference).

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10.27 |  | Amendment No. 1 to Amended and Restated Credit Agreement, dated March 26, 2019, among Patterson-UTI Energy, Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent, letter of credit issuer, swing line lender and lender and each of the other letter of credit issuers and lenders party thereto (filed March 26, 2019 as Exhibit 10.1 to our Current Report on Form 8-K and incorporated herein by reference).
10.28 |  | Amendment No. 2 to Amended and Restated Credit Agreement, dated March 27, 2020, among Patterson-UTI Energy, Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent, letter of credit issuer, swing line lender and lender and each of the other letter of credit issuers and lenders party thereto (filed March 27, 2020 as Exhibit 10.1 to our Current Report on Form 8-K and incorporated herein by reference).
10.29 |  | Amendment No. 3 to Amended and Restated Credit Agreement, dated November 9, 2022, among Patterson-UTI Energy, Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent, letter of credit issuer, swing line lender and lender and each of the other letter of credit issuers and lenders party thereto (filed November 9, 2022 as Exhibit 10.1 to our Current Report on Form 8-K and incorporated herein by reference).
10.30 |  | Amendment No. 4 to Amended and Restated Credit Agreement, dated August 29, 2023, 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.(filed September 1, 2023 as Exhibit 10.2 to our Current Report on Form 8-K and incorporated herein by reference).
10.31 |  | Commitment Increase Agreement, dated April 5, 2024, by and among Patterson-UTI Energy, Inc., Citibank, N.A., HSBC Bank USA, National Association, Wells Fargo Bank, N.A., as administrative agent, letter of credit issuer and swing line lender and the other letter of credit issuers party thereto (filed May 6, 2024 as Exhibit 10.1 to our Quarterly Report on Form 10-Q and incorporated herein by reference).
10.32 |  | 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).
10.33 |  | Reimbursement Agreement, dated as of March 16, 2015, by and between Patterson-UTI Energy, Inc. and The Bank of Nova Scotia (filed March 16, 2015 as Exhibit 10.1 to our Current Report on Form 8-K and incorporated herein by reference).
10.34 |  | Amendment No. 1 to Reimbursement Agreement, dated as of October 16, 2024, by and between Patterson-UTI Energy, Inc. and The Bank of Nova Scotia.+
19.1 |  | Insider Trading Compliance Policy.+
19.2 |  | Insider Trading Compliance Memorandum.+
21.1 |  | Subsidiaries of the Registrant.+
23.1 |  | Consent of Independent Registered Public Accounting Firm.+
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.++
97 |  | Patterson-UTI Energy, Inc. Clawback Policy (filed February 27, 2024 as Exhibit 97 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2023 and incorporated herein by reference).

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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 |  | Cover Page Interactive Data File (formatted as inline XBRL with applicable taxonomy extension information contained in Exhibits 101).

________________________________
*Management Contract or Compensatory Plan identified as required by Item 15(a)(3) of Form 10-K.
+Filed herewith.
++Furnished herewith.
Item 16. Form 10-K Summary
None.
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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

| Page
Report of Independent Registered Public Accounting Firm | F-2
Consolidated Financial Statements: |
Consolidated Balance Sheets as of December 31, 2024 and 2023 | F-4
Consolidated Statements of Operations for the years ended December 31, 2024, 2023 and 2022 | F-5
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2024, 2023 and 2022 | F-6
Consolidated Statements of Changes in Stockholders’ Equity for the years ended December 31, 2024, 2023 and 2022 | F-7
Consolidated Statements of Cash Flows for the years ended December 31, 2024, 2023 and 2022 | F-8
Notes to Consolidated Financial Statements | F-9

F-1

Table of Contents
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Patterson-UTI Energy, Inc.
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Patterson-UTI Energy, Inc. and its subsidiaries (the "Company") as of December 31, 2024 and 2023, and the related consolidated statements of operations, of comprehensive income (loss), of changes in stockholders’ equity and of cash flows for each of the three years in the period ended December 31, 2024, including the related notes and schedule of valuation and qualifying accounts for each of the three years in the period ended December 31, 2024 appearing on page S-1 (collectively referred to as the "consolidated financial statements"). We also have audited the Company's internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are
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material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Goodwill Impairment Assessment – Drilling Products Reporting Unit
As described in Note 7 to the consolidated financial statements, the Company’s goodwill balance for the drilling products reporting unit was $450.5 million as of December 31, 2024. Management evaluates goodwill for impairment at least annually on July 31, or more frequently when events and circumstances occur indicating recorded goodwill may be impaired. Management estimated the fair value of the drilling products reporting unit using the income approach. Under this approach, management used a discounted cash flow model, which utilizes present values of cash flows to estimate fair value. 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 the reporting unit consisted of a growth estimate. Future cash flows were then discounted using a market-participant, risk-adjusted weighted average cost of capital.
The principal considerations for our determination that performing procedures relating to the goodwill impairment assessment of the drilling products reporting unit is a critical audit matter are (i) the significant judgment by management when developing the fair value estimate of the drilling products reporting unit; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions related to estimates of certain revenue growth rates and the discount rate; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s goodwill impairment assessment, including controls over the valuation of the drilling products reporting unit. These procedures also included, among others (i) testing management’s process for developing the fair value estimate of the drilling products reporting unit; (ii) evaluating the appropriateness of the income approach used by management; (iii) testing the completeness and accuracy of the underlying data used in the income approach; and (iv) evaluating the reasonableness of the significant assumptions used by management related to estimates of certain revenue growth rates and the discount rate. Evaluating management’s assumption related to estimates of certain revenue growth rates involved evaluating whether the assumption used by management was reasonable considering (i) the current and past performance of the drilling products reporting unit; (ii) the consistency with external market and industry data; and (iii) whether the assumption was consistent with evidence obtained in other areas of the audit. Professionals with specialized skill and knowledge were used to assist in evaluating (i) the appropriateness of the income approach and (ii) the reasonableness of the discount rate assumption.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 11, 2025
We have served as the Company’s auditor since 1993.
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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

| December 31,
| 2024 |  | 2023
| (In thousands, except share data)
ASSETS |  |  |
Current assets: |  |  |
Cash, cash equivalents and restricted cash | $ | 241,293 |  |  | $ | 192,680 |
Accounts receivable, net of allowance for credit losses of $15,047 and $3,490 at December 31, 2024 and 2023, respectively | 763,806 |  |  | 971,091 |
Inventory | 167,023 |  |  | 180,805 |
Other current assets | 123,193 |  |  | 141,122 |
Total current assets | 1,295,315 |  |  | 1,485,698 |
Property and equipment, net | 3,010,342 |  |  | 3,340,412 |
Operating lease right of use asset | 44,385 |  |  | 47,599 |
Finance lease right of use asset | 27,018 |  |  | 63,228 |
Goodwill | 487,388 |  |  | 1,379,741 |
Intangible assets, net | 929,610 |  |  | 1,051,697 |
Deposits on equipment purchases | 15,699 |  |  | 28,305 |
Other assets | 23,709 |  |  | 19,424 |
Deferred tax assets, net | — |  |  | 3,927 |
Total assets | $ | 5,833,466 |  |  | $ | 7,420,031 |
LIABILITIES AND STOCKHOLDERS’ EQUITY |  |  |
Current liabilities: |  |  |
Accounts payable | $ | 421,318 |  |  | $ | 534,420 |
Accrued liabilities | 385,751 |  |  | 446,268 |
Operating lease liability | 13,322 |  |  | 13,541 |
Finance lease liability | 15,214 |  |  | 43,980 |
Current maturities of long-term debt | 6,388 |  |  | 12,226 |
Total current liabilities | 841,993 |  |  | 1,050,435 |
Long-term operating lease liability | 34,305 |  |  | 37,848 |
Long-term finance lease liability | 10,216 |  |  | 12,953 |
Long-term debt, net of debt discount and issuance costs of $7,637 and $8,919 at December 31, 2024 and 2023, respectively | 1,219,770 |  |  | 1,224,941 |
Deferred tax liabilities, net | 238,097 |  |  | 248,107 |
Other liabilities | 13,241 |  |  | 25,066 |
Total liabilities | 2,357,622 |  |  | 2,599,350 |
Commitments and contingencies (see Note 10) |  |  |
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 and 800,000,000 shares with 520,784,783 and 516,775,313 issued and 387,344,755 and 411,195,302 outstanding at December 31, 2024 and 2023, respectively | 5,206 |  |  | 5,166 |
Additional paid-in capital | 6,453,606 |  |  | 6,407,294 |
Retained earnings (deficit) | (1,039,338) |  |  | 57,035 |
Accumulated other comprehensive income (loss) | (2,584) |  |  | 472 |
Treasury stock, at cost, 133,440,028 shares and 105,580,011 shares at December 31, 2024 and 2023, respectively | (1,951,067) |  |  | (1,657,675) |
Total stockholders’ equity attributable to controlling interests | 3,465,823 |  |  | 4,812,292 |
Noncontrolling interest | 10,021 |  |  | 8,389 |
Total equity | 3,475,844 |  |  | 4,820,681 |
Total liabilities and stockholders’ equity | $ | 5,833,466 |  |  | $ | 7,420,031 |

The accompanying notes are an integral part of these consolidated financial statements.
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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS

| Year Ended December 31, |  |  |  |  |  |  |  |  |  |  |
| 2024 |  | 2023 |  | 2022 |  |  |  |  |  |  |  |  |  |  |
| (In thousands, except per share data) |  |  |  |  |  |  |  |  |  |  |
Operating revenues: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Drilling Services | $ | 1,727,810 |  |  | $ | 1,919,759 |  |  | $ | 1,544,820 |  |  |  |  |  |  |  |  |  |  |  |
Completion Services | 3,232,785 |  |  | 2,017,440 |  |  | 1,022,413 |  |  |  |  |  |  |  |  |  |  |  |
Drilling Products | 351,651 |  |  | 134,679 |  |  | — |  |  |  |  |  |  |  |  |  |  |  |
Other | 65,665 |  |  | 74,578 |  |  | 80,359 |  |  |  |  |  |  |  |  |  |  |  |
Total operating revenues | 5,377,911 |  |  | 4,146,456 |  |  | 2,647,592 |  |  |  |  |  |  |  |  |  |  |  |
Operating costs and expenses: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Drilling Services | 1,029,591 |  |  | 1,119,200 |  |  | 1,025,904 |  |  |  |  |  |  |  |  |  |  |  |
Completion Services | 2,658,170 |  |  | 1,567,940 |  |  | 781,385 |  |  |  |  |  |  |  |  |  |  |  |
Drilling Products | 191,107 |  |  | 81,555 |  |  | — |  |  |  |  |  |  |  |  |  |  |  |
Other | 41,001 |  |  | 42,624 |  |  | 39,261 |  |  |  |  |  |  |  |  |  |  |  |
Depreciation, depletion, amortization and impairment | 1,171,873 |  |  | 731,416 |  |  | 483,945 |  |  |  |  |  |  |  |  |  |  |  |
Impairment of goodwill | 885,240 |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |  |
Selling, general and administrative | 268,337 |  |  | 169,962 |  |  | 116,589 |  |  |  |  |  |  |  |  |  |  |  |
Merger and integration expense | 33,037 |  |  | 98,077 |  |  | 2,069 |  |  |  |  |  |  |  |  |  |  |  |
Other operating income, net | (10,708) |  |  | (16,272) |  |  | (12,592) |  |  |  |  |  |  |  |  |  |  |  |
Total operating costs and expenses | 6,267,648 |  |  | 3,794,502 |  |  | 2,436,561 |  |  |  |  |  |  |  |  |  |  |  |
Operating income (loss) | (889,737) |  |  | 351,954 |  |  | 211,031 |  |  |  |  |  |  |  |  |  |  |  |
Other income (expense): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Interest income | 5,729 |  |  | 6,122 |  |  | 360 |  |  |  |  |  |  |  |  |  |  |  |
Interest expense, net of amount capitalized | (71,963) |  |  | (52,870) |  |  | (40,256) |  |  |  |  |  |  |  |  |  |  |  |
Other income (expense) | (975) |  |  | 1,898 |  |  | (3,273) |  |  |  |  |  |  |  |  |  |  |  |
Total other income (expense) | (67,209) |  |  | (44,850) |  |  | (43,169) |  |  |  |  |  |  |  |  |  |  |  |
Income (loss) before income taxes | (956,946) |  |  | 307,104 |  |  | 167,862 |  |  |  |  |  |  |  |  |  |  |  |
Income tax expense | 9,453 |  |  | 61,152 |  |  | 13,204 |  |  |  |  |  |  |  |  |  |  |  |
Net income (loss) | (966,399) |  |  | 245,952 |  |  | 154,658 |  |  |  |  |  |  |  |  |  |  |  |
Net income (loss) attributable to noncontrolling interest | 1,632 |  |  | (340) |  |  | — |  |  |  |  |  |  |  |  |  |  |  |
Net income (loss) attributable to common stockholders | $ | (968,031) |  |  | $ | 246,292 |  |  | $ | 154,658 |  |  |  |  |  |  |  |  |  |  |  |
Net income (loss) attributable to common stockholder per common share: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Basic | $ | (2.44) |  |  | $ | 0.88 |  |  | $ | 0.72 |  |  |  |  |  |  |  |  |  |  |  |
Diluted | $ | (2.44) |  |  | $ | 0.88 |  |  | $ | 0.70 |  |  |  |  |  |  |  |  |  |  |  |
Weighted average number of common shares outstanding: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Basic | 397,196 |  | 279,501 |  | 215,935 |  |  |  |  |  |  |  |  |  |  |
Diluted | 397,196 |  | 280,061 |  | 219,496 |  |  |  |  |  |  |  |  |  |  |

The accompanying notes are an integral part of these consolidated financial statements.
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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

| Year Ended December 31,
| 2024 |  | 2023 |  | 2022
| (In thousands)
Net income (loss) | $ | (966,399) |  |  | $ | 245,952 |  |  | $ | 154,658 |
Other comprehensive income (loss): |  |  |  |  |
Foreign currency translation adjustment, net of taxes of $0 for all periods | (3,056) |  |  | 472 |  |  | 1,793 |
Release of cumulative translation adjustment, net of taxes of $0 for 2024 and 2023 and $3,770 for 2022 | — |  |  | — |  |  | (7,708) |
Comprehensive income (loss) | (969,455) |  |  | 246,424 |  |  | 148,743 |
Less: comprehensive income (loss) attributable to noncontrolling interest | 1,632 |  |  | (340) |  |  | — |
Comprehensive income (loss) attributable to common stockholders | $ | (971,087) |  |  | $ | 246,764 |  |  | $ | 148,743 |

The accompanying notes are an integral part of these consolidated financial statements.
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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

| Common Stock |  | Additional Paid-in Capital |  | Retained Earnings (Deficit) |  | Accumulated Other Comprehensive Income (Loss) |  | Treasury Stock |  | Noncontrolling Interest |  | Total
| Number of Shares |  | Amount |  |  |  |  |  |
| (In thousands)
Balance, December 31, 2021 | 299,269 |  | $ | 2,993 |  |  | $ | 3,171,536 |  |  | $ | (198,316) |  |  | $ | 5,915 |  |  | $ | (1,372,641) |  |  | — |  |  | $ | 1,609,487 |
Net income | — |  | — |  |  | — |  |  | 154,658 |  |  | — |  |  | — |  |  | — |  |  | 154,658 |
Foreign currency translation adjustment | — |  | — |  |  | — |  |  | — |  |  | 1,793 |  |  | — |  |  | — |  |  | 1,793 |
Release of cumulative translation adjustment | — |  | — |  |  | — |  |  | — |  |  | (7,708) |  |  | — |  |  | — |  |  | (7,708) |
Issuance of restricted stock | 980 |  | 10 |  |  | (10) |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Vesting of restricted stock units | 1,437 |  | 14 |  |  | (14) |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Exercise of stock options | 640 |  | 6 |  |  | 10,362 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 10,368 |
Stock-based compensation | — |  | — |  |  | 21,099 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 21,099 |
Payment of cash dividends ($0.20 per share) | — |  | — |  |  | — |  |  | (43,096) |  |  | — |  |  | — |  |  | — |  |  | (43,096) |
Dividend equivalents | — |  | — |  |  | — |  |  | (640) |  |  | — |  |  | — |  |  | — |  |  | (640) |
Purchase of treasury stock | — |  | — |  |  | — |  |  | — |  |  | — |  |  | (80,438) |  |  | — |  |  | (80,438) |
Balance, December 31, 2022 | 302,326 |  | $ | 3,023 |  |  | $ | 3,202,973 |  |  | $ | (87,394) |  |  | $ | — |  |  | $ | (1,453,079) |  |  | $ | — |  |  | $ | 1,665,523 |
Net income | — |  | — |  |  | — |  |  | 246,292 |  |  | — |  |  | — |  |  | (340) |  |  | 245,952 |
Noncontrolling interest | — |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 8,729 |  |  | 8,729 |
Foreign currency translation adjustment | — |  | — |  |  | — |  |  | — |  |  | 472 |  |  | — |  |  | — |  |  | 472 |
Issuance of common stock - Ulterra acquisition | 34,900 |  | 349 |  |  | 521,057 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 521,406 |
Issuance of common stock - NexTier merger | 172,092 |  | 1,720 |  |  | 2,564,175 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 2,565,895 |
Issuance of replacement awards related to NexTier merger | — |  | — |  |  | 72,413 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 72,413 |
Issuance of restricted stock | 1,077 |  | 10 |  |  | (10) |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Vesting of restricted stock units | 6,380 |  | 64 |  |  | (64) |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Stock-based compensation | — |  | — |  |  | 46,750 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 46,750 |
Payment of cash dividends ($0.32 per share) | — |  | — |  |  | — |  |  | (100,034) |  |  | — |  |  | — |  |  | — |  |  | (100,034) |
Dividend equivalents | — |  | — |  |  | — |  |  | (1,829) |  |  | — |  |  | — |  |  | — |  |  | (1,829) |
Purchase of treasury stock | — |  | — |  |  | — |  |  | — |  |  | — |  |  | (204,596) |  |  | — |  |  | (204,596) |
Balance, December 31, 2023 | 516,775 |  | $ | 5,166 |  |  | $ | 6,407,294 |  |  | $ | 57,035 |  |  | $ | 472 |  |  | $ | (1,657,675) |  |  | $ | 8,389 |  |  | $ | 4,820,681 |
Net income (loss) | — |  | — |  |  | — |  |  | (968,031) |  |  | — |  |  | — |  |  | 1,632 |  |  | (966,399) |
Foreign currency translation adjustment | — |  | — |  |  | — |  |  | — |  |  | (3,056) |  |  | — |  |  | — |  |  | (3,056) |
Issuance of restricted stock | 719 |  | 7 |  |  | (7) |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Vesting of restricted stock units | 3,291 |  | 33 |  |  | (33) |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Stock-based compensation | — |  | — |  |  | 46,352 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 46,352 |
Payment of cash dividends ($0.32 per share) | — |  | — |  |  | — |  |  | (126,791) |  |  | — |  |  | — |  |  | — |  |  | (126,791) |
Dividend equivalents | — |  | — |  |  | — |  |  | (1,551) |  |  | — |  |  | — |  |  | — |  |  | (1,551) |
Purchase of treasury stock | — |  | — |  |  | — |  |  | — |  |  | — |  |  | (293,392) |  |  | — |  |  | (293,392) |
Balance, December 31, 2024 | 520,785 |  | $ | 5,206 |  |  | $ | 6,453,606 |  |  | $ | (1,039,338) |  |  | $ | (2,584) |  |  | $ | (1,951,067) |  |  | $ | 10,021 |  |  | $ | 3,475,844 |

The accompanying notes are an integral part of these consolidated financial statements.
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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

| Year Ended December 31, |  |  |  |
| 2024 |  | 2023 |  | 2022 |  |  |  |
| (In thousands) |  |  |  |
Cash flows from operating activities: |  |  |  |  |  |  |  |  |
Net income (loss) | $ | (966,399) |  |  | $ | 245,952 |  |  | $ | 154,658 |  |  |  |  |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |  |  |  |  |  |  |  |  |
Depreciation, depletion, amortization and impairment | 1,171,873 |  |  | 731,416 |  |  | 483,945 |  |  |  |  |
Impairment of goodwill | 885,240 |  |  | — |  |  | — |  |  |  |  |
Deferred income tax expense (benefit) | (1,765) |  |  | 51,866 |  |  | 6,998 |  |  |  |  |
Stock-based compensation | 46,352 |  |  | 46,750 |  |  | 21,099 |  |  |  |  |
Net gain on asset disposals | (3,688) |  |  | (1,798) |  |  | (12,075) |  |  |  |  |
Other | 7,936 |  |  | (1,053) |  |  | (1,507) |  |  |  |  |
Changes in operating assets and liabilities: |  |  |  |  |  |  |  |  |
Accounts receivable | 203,652 |  |  | 84,544 |  |  | (209,226) |  |  |  |  |
Inventory | (11,463) |  |  | (30,793) |  |  | (23,154) |  |  |  |  |
Other current assets | 19,599 |  |  | (10,360) |  |  | (1,975) |  |  |  |  |
Other assets | 33,760 |  |  | 24,686 |  |  | 10,643 |  |  |  |  |
Accounts payable | (112,858) |  |  | (69,729) |  |  | 38,986 |  |  |  |  |
Accrued liabilities | (66,582) |  |  | (23,484) |  |  | 67,380 |  |  |  |  |
Other liabilities | (30,121) |  |  | (42,083) |  |  | 30,416 |  |  |  |  |
Net cash provided by operating activities | 1,175,536 |  |  | 1,005,914 |  |  | 566,188 |  |  |  |  |
Cash flows from investing activities: |  |  |  |  |  |  |  |  |
Acquisitions, net of cash acquired - NexTier | — |  |  | (65,185) |  |  | — |  |  |  |  |
Acquisitions, net of cash acquired - Ulterra | 2,983 |  |  | (357,314) |  |  | — |  |  |  |  |
Purchases of property and equipment | (678,386) |  |  | (615,690) |  |  | (436,797) |  |  |  |  |
Proceeds from disposal of assets | 25,832 |  |  | 26,473 |  |  | 26,074 |  |  |  |  |
Other | (5,173) |  |  | (5,874) |  |  | (2,504) |  |  |  |  |
Net cash used in investing activities | (654,744) |  |  | (1,017,590) |  |  | (413,227) |  |  |  |  |
Cash flows from financing activities: |  |  |  |  |  |  |  |  |
Purchases of treasury stock | (290,427) |  |  | (200,710) |  |  | (70,070) |  |  |  |  |
Dividends paid | (126,791) |  |  | (100,034) |  |  | (43,096) |  |  |  |  |
Proceeds from borrowings under revolving credit facility | 50,000 |  |  | 420,000 |  |  | 150,000 |  |  |  |  |
Repayment of borrowings under revolving credit facility | (50,000) |  |  | (420,000) |  |  | (150,000) |  |  |  |  |
Proceeds from issuance of senior notes | — |  |  | 396,412 |  |  | — |  |  |  |  |
Repayment of senior notes | — |  |  | (7,837) |  |  | (19,760) |  |  |  |  |
Payments on finance leases | (45,484) |  |  | (15,915) |  |  | — |  |  |  |  |
Other | (12,290) |  |  | (6,349) |  |  | (455) |  |  |  |  |
Net cash provided by (used in) financing activities | (474,992) |  |  | 65,567 |  |  | (133,381) |  |  |  |  |
Effect of foreign exchange rate changes on cash, cash equivalents and restricted cash | 2,813 |  |  | 1,236 |  |  | 449 |  |  |  |  |
Net increase in cash, cash equivalents and restricted cash | 48,613 |  |  | 55,127 |  |  | 20,029 |  |  |  |  |
Cash, cash equivalents and restricted cash at beginning of year | 192,680 |  |  | 137,553 |  |  | 117,524 |  |  |  |  |
Cash, cash equivalents and restricted cash at end of year | $ | 241,293 |  |  | $ | 192,680 |  |  | $ | 137,553 |  |  |  |  |
Supplemental disclosure of cash flow information: |  |  |  |  |  |  |  |  |
Net cash (paid) received during the year for: |  |  |  |  |  |  |  |  |
Interest, net of capitalized interest of $1,334 in 2024, $1,692 in 2023, and $976 in 2022 | $ | (68,563) |  |  | $ | (39,607) |  |  | $ | (39,855) |  |  |  |  |
Income taxes | (14,767) |  |  | (27,169) |  |  | (1,526) |  |  |  |  |
Non-cash investing and financing activities: |  |  |  |  |  |  |  |  |
Net increase (decrease) in payables for purchases of property and equipment | $ | (133) |  |  | $ | (15,111) |  |  | $ | 7,953 |  |  |  |  |
Net (increase) decrease in deposits on equipment purchases | 12,607 |  |  | 7,876 |  |  | (12,202) |  |  |  |  |
Issuance of common stock for business acquisitions | — |  |  | 3,159,714 |  |  | — |  |  |  |  |
Cashless exercise of stock options | — |  |  | — |  |  | 10,368 |  |  |  |  |
Purchases of property and equipment through exchange of lease right of use asset | 30,961 |  |  | 3,241 |  |  | — |  |  |  |  |
Derecognition of right of use asset | (36,117) |  |  | (3,241) |  |  | — |  |  |  |  |

The accompanying notes are an integral part of these consolidated financial statements.
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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Description of Business and Summary of Significant Accounting Policies
A description of the business and basis of presentation follows:
Description of business — Patterson-UTI Energy, Inc., through its wholly-owned subsidiaries and consolidating interest of a joint venture (collectively referred to herein as “we,” “us,” “our,” “ours” and like terms), is 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. We have other operations through which we provide oilfield rental tools in select markets in the United States. In addition, we own and invest, as a non-operating, working interest owner, in oil and natural gas assets that are primarily located in Texas and New Mexico.
On August 14, 2023, we completed our acquisition (the “Ulterra acquisition”) of Ulterra Drilling Technologies, L.P. (“Ulterra”), a global provider of specialized drill bit solutions. On September 1, 2023, we completed our merger (the “NexTier merger”) with NexTier Oilfield Solutions Inc. (“NexTier”), a predominately U.S. land-focused oilfield service provider, with a diverse set of well completion and production services across a variety of active basins. See Note 2 for additional details on the acquisition and merger.
Basis of presentation — The consolidated financial statements include the accounts of Patterson-UTI, its wholly-owned subsidiaries and the consolidating interest of a joint venture. All intercompany accounts and transactions have been eliminated. Except for wholly-owned subsidiaries and our interest in a joint venture, we have no controlling financial interests in any other entity which would require consolidation. As used in these notes, “we,” “us,” “our,” “ours” and like terms refer collectively to Patterson-UTI Energy, Inc, and its consolidated subsidiaries. Patterson-UTI Energy, Inc. conducts its business operations through its wholly-owned subsidiaries and has no employees or independent operations. Certain 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 consolidated financial statements for the year ended December 31, 2023 include the results of Ulterra from August 14, 2023, and the results of NexTier from September 1, 2023.
A summary of the significant accounting policies follows:
Management estimates — The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from such estimates.
Cash and cash equivalents — Cash equivalents are highly liquid, short-term investments with original maturities of three months or less from their date of purchase.
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 consolidated balance sheets that sum to the total of such amounts shown in the statements of cash flows for the years ended December 31, 2024 and 2023:

| Year Ended December 31,
| 2024 |  | 2023
Cash and cash equivalents | $ | 239,182 |  |  | $ | 190,108 |
Restricted cash | 2,111 |  |  | 2,572 |
Total cash, cash equivalents and restricted cash | $ | 241,293 |  |  | $ | 192,680 |

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Accounts receivable — Trade accounts receivable are recorded at the invoiced amount. The allowance for credit losses represents our estimate of the amount of probable credit losses existing in our accounts receivable. Significant individual accounts receivable balances and balances which have been outstanding greater than 90 days are reviewed individually for collectability. Account balances, when determined to be uncollectible, are charged against the allowance.
Inventories — Inventories consist primarily of sand and other products to be used in conjunction with our completion services activities, materials used in our equipment servicing business, spare parts for drilling services and raw materials for drilling products. Such inventories are stated at the lower of cost or net realizable value. The majority of our inventory is recorded using weighted average cost.
We periodically review the nature and quantities of inventory on hand and evaluate the net realizable value of items based on historical usage patterns, known changes to equipment or processes and customer demand for specific products. Provision for excess or obsolete inventories is determined based on historical usage of inventory on-hand, volume on-hand versus anticipated usage, technological advances and consideration of current market conditions. Inventories that have not turned over for more than a year are subject to slow-moving reserve provisions. In addition, inventories that have become obsolete due to technological advances or are no longer configured to operate with our equipment are written off.
Other current assets — Other current assets include reimbursement from our workers compensation insurance carrier for claims in excess of our deductible in the amount of $33.2 million and $31.0 million at December 31, 2024 and 2023, respectively. We also maintain prepayments for items such as insurance, rent and inventory.
Long-lived assets with definite lives — Property and equipment and definite-lived intangible assets are carried at cost less accumulated depreciation, amortization, depletion and impairment. Depreciation and amortization is recorded on the straight-line method over the estimated useful lives.
The estimated useful lives are shown below:

| Useful Lives
Equipment | 1-25 years
Rental equipment | 4-8 runs
Buildings and leasehold improvements | 1-30 years
Other | 3-20 years

Amortization of definite-lived intangible assets is calculated on the straight-lined method over the estimated useful lives of the assets, which range from 3 to 15 years.
Long-lived assets with definite lives, including property and equipment and certain intangible assets, are evaluated 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”). Assets are grouped at the lowest level at which identifiable cash flows are largely independent of other asset groupings for impairment assessment. If there is a triggering event, we estimate future cash flows over the life of the respective assets or asset groupings in our assessment of its recoverability. 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. If estimated undiscounted cash flows expected to result from the use and eventual disposition of an asset or asset group is less than its respective carrying amount, an impairment loss is recognized in the amount by which the carrying amount exceeds its estimated fair value.
Maintenance and repairs — Maintenance and repairs are charged to expense when incurred. Renewals and betterments which extend the life or improve existing property and equipment are capitalized.
Disposals — Upon disposition of property and equipment, the cost and related accumulated depreciation are removed and any resulting gain or loss is reflected in our consolidated statements of operations.
Goodwill — As a result of both the Ulterra acquisition and the NexTier merger, we have recognized goodwill. Goodwill from acquisitions is recorded as the excess of the consideration transferred plus the fair value of any non-controlling interest in the acquiree at the acquisition date over the fair values of the identifiable net assets acquired. Goodwill is considered to have an indefinite useful economic life and is not amortized. We assess impairment of goodwill at least annually, as of July 31, or on an interim basis if events or circumstances indicate that the fair value of goodwill may have decreased below its carrying value. If the carrying value of a reporting unit exceeds its fair value, we recognize an impairment in an amount equal to the excess, limited to the total amount of
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goodwill allocated to the reporting unit. During the third quarter of 2024, we recorded an $885 million impairment charge to goodwill related to our completion services reporting unit. See Note 7 for details.
Leases — We have operating leases for operating locations, corporate offices and certain operating equipment. We determine if a contract contains a lease at inception or as a result of an acquisition. A right-of-use asset and corresponding lease liability are recognized on our consolidated balance sheet at commencement at an amount based on the present value of the remaining lease payments over the lease term. The lease term may include the option to extend or terminate the lease when it is reasonably certain that we will exercise the option. By our policy election, right-of-use assets and lease liabilities with an initial term of one year or less are not recognized for leasing arrangements, and non-lease and lease components are treated as a single lease component instead of bifurcating those components. Lease expense is recognized on a straight-line basis. If available, we use the rate implicit in the lease at commencement date to discount the lease payments. If the implicit rate is not readily determinable, we use our incremental borrowing rate based on the information available at the commencement date in the determination of the present value of future lease payments.
For finance leases, we amortize the right-of-use asset on a straight-line basis over the earlier of the useful life of the right-of-use asset or the end of the lease term and record this amortization in depreciation and amortization expense in the consolidated statements of operations. If available, we use the rate implicit in the lease at commencement date to discount the lease payments. If the implicit rate is not available, we use our incremental borrowing rate based on the information available at the commencement date in the determination of the present value of future lease payments. The lease term may include the option to extend or terminate the lease when it is reasonably certain that we will exercise the option. By our policy election, right-of-use assets and lease liabilities with an initial term of one year or less are not recognized for leasing arrangements, and non-lease and lease components are treated as a single lease component instead of bifurcating those components. For finance leases where we have determined we are reasonably certain to exercise a purchase option to acquire the underlying asset, we amortize the right-of-use asset over the lease term and record this amortization in “Depreciation, depletion, amortization and impairment” in the consolidated statements of operations. We adjust the lease liability to reflect lease payments made during the period and interest incurred on the lease liability using the effective interest method. The incurred interest expense is recorded in “Interest expense” in the consolidated statements of operations.
In the third quarter of 2023, as part of the Ulterra acquisition and the NexTier merger, we acquired certain operating and finance leases. We inherited NexTier’s and Ulterra’s lease classifications as of the time of each respective acquisition. We elected as an accounting policy election by class of underlying assets to not recognize assets or liabilities at the acquisition date for leases that had a remaining lease term of twelve months or less. See Notes 2 and 13 for details.
Revenue recognition — Revenues from our drilling services, completion services, drilling products, and other activities are recognized upon the transfer of control of the related services and products to the customer. See Note 3 for details.
Income taxes — The asset and liability method is used in accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for operating loss and tax credit carryforwards and for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the results of operations in the period that includes the enactment date. If applicable, a valuation allowance is recorded to reduce the carrying amounts of deferred tax assets unless it is more likely than not that such assets will be realized. Our policy is to account for interest and penalties with respect to income taxes as operating expenses.
Stock-based compensation — We recognize the cost of share-based payments under the fair-value-based method. Under this method, compensation cost related to share-based payments is measured based on the estimated fair value of the awards at the date of grant, net of estimated forfeitures. This expense is recognized over the expected life of the awards, as described in Note 12.
Concentration of Credit Risk — Our assets that are potentially subject to concentrations of credit risk are cash, cash equivalents and restricted cash and trade accounts receivable. Cash balances are maintained in financial institutions, which at times exceed federally insured limits. We monitor the financial condition of the financial institutions in which accounts are maintained and we have not experienced any losses in such accounts. We maintain an allowance for credit losses based upon several factors, including historical collection experience, current aging status of the customer accounts and financial condition of our customers. There were no material changes in the allowance for credit losses in 2024 and 2023.
Recently Adopted Accounting Standards — In March 2020, the FASB issued an accounting standards update to provide temporary optional expedients that simplify the accounting for contract modifications to existing debt agreements expected to arise from the market transition from LIBOR to alternative reference rates. The guidance was effective upon issuance and generally can be applied to applicable contract modifications through December 31, 2024. We adopted the optional relief guidance provided under Topic 848 after modifying our debt agreements to update the reference rate from LIBOR to SOFR or Prime Rate. The adoption of the new guidance did not have a material impact on our financial statements.
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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 17 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 reflected in our 2025 fiscal year Form 10-K. 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.
2. Business Combinations
Ulterra Drilling Technologies, L.P.
On August 14, 2023, we completed the Ulterra acquisition. Total consideration for the acquisition included the issuance of 34.9 million shares of our common stock and payment of approximately $373 million of cash (after purchase price adjustments), which based on the closing price of our common stock of $14.94 on August 14, 2023, valued the transaction at closing at approximately $894 million.
The total fair value of the consideration transferred was determined as follows (in thousands, except stock price):

Shares of our common stock issued to Ulterra | 34,900
Our common stock price on August 14, 2023 | $ | 14.94 |
Common stock equity consideration | $ | 521,406 |
Plus net cash consideration | 372,757 |
Total consideration transferred | $ | 894,163 |

The acquisition was accounted for as a business combination using the acquisition method. Under the acquisition method of accounting, the fair value of the consideration transferred is allocated to the tangible and intangible assets acquired and the liabilities assumed based on their estimated fair values as of the acquisition date.
The aggregate purchase price noted above was allocated to the major categories of assets acquired and liabilities assumed based on preliminary estimated fair values as of the date of the business combination. We applied significant judgment in estimating the fair value of assets acquired and liabilities assumed, which involved the use of significant estimates and assumptions with respect to future rig counts, cash flow projections, estimated economic useful lives, operating and capital cost estimates, customer attrition rates, contributory asset charges, royalty rates and discount rate (10.5%). The carrying amounts of cash and cash equivalents, accounts receivable, other assets, accounts payable and accrued liabilities approximate their fair values due to their nature or the short-term maturity of instruments. The remaining assets acquired and liabilities assumed are based on inputs that are not observable in the market and thus represent Level 3 inputs. The fair value of inventory and rental equipment was determined using a replacement cost approach. Intangible assets primarily consist of customer relationships and developed technology, the fair values of which were determined using an income approach. Property and equipment was valued using a combination of indirect cost and a market approach. The fair value was estimated by using a multi-period excess earnings method for customer relationships and a relief from royalty method for trade name and developed technology. The purchase price allocation was finalized in the third quarter of 2024. The valuation period adjustments did not have a material impact on our consolidated financial statements.
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The following table summarizes the fair values of the assets acquired and liabilities assumed at the date of acquisition:

Assets acquired: |
Cash and cash equivalents | $ | 18,426 |
Accounts receivable | 68,467 |
Inventory (1) | 36,313 |
Rental equipment (2) | 109,055 |
Property and equipment | 27,583 |
Intangible assets | 313,000 |
Operating lease right of use asset | 7,513 |
Finance lease right of use asset | 5,228 |
Other assets | 15,989 |
Total assets acquired | 601,574 |
Liabilities assumed: |
Accounts payable | 23,258 |
Accrued liabilities | 33,323 |
Operating lease liability | 7,513 |
Finance lease liability | 5,228 |
Deferred tax liabilities | 79,863 |
Total liabilities assumed | 149,185 |
Less: noncontrolling interest | (8,729) |
Net assets acquired | 443,660 |
Goodwill | 450,503 |
Total consideration transferred | $ | 894,163 |

(1)We recorded a n adjustment of $5.5 million to write-up acquired drill bits classified as inventory to estimated fair value. This adjustment will be recorded as direct operating expense as acquired drill bits are sold.
(2)We recorded an adjustment of $74.4 million to write-up acquired drill bits classified as long-lived assets to estimated fair value. This adjustment will be depreciated as acquired drill bits are rented over a weighted-average estimated useful life of 7.5 runs.
The goodwill recognized in the acquisition represents the excess of the gross consideration transferred over the fair value of the underlying net tangible and identifiable intangible assets acquired and liabilities assumed. Goodwill represents the potential for new growth opportunities internationally with the acquisition of Ulterra as well as the recognition of deferred taxes for the difference between the fair value of the assets acquired and liabilities assumed and the respective carry-over tax basis. Goodwill is not deductible for tax purposes. All of the goodwill was assigned to our Drilling Products segment. See Note 7.
Approximately $135 million of revenues and $3.4 million of net loss attributed to the Ulterra acquisition are included in the consolidated statements of operations for the period from the closing date on August 14, 2023 through December 31, 2023. We incurred $5.6 million of merger and integration expense related to the Ulterra acquisition in 2023. We did not incur any material merger and integration expense related to the Ulterra acquisition in 2024.
A portion of the fair value consideration transferred has been provisionally assigned to identifiable intangible assets as follows:

| Fair Value (in thousands) |  | Weighted Average Useful Life (in years)
Customer relationships | $ | 245,000 |  |  | 15
Trade name | 16,000 |  |  | 11
Developed technology | 52,000 |  |  | 5
Intangible assets | $ | 313,000 |  |  |

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Pro Forma
The following pro forma condensed combined financial information was derived from our and Ulterra’s historical financial statements and gives effect to the acquisition as if it had occurred on January 1, 2022. The below information reflects pro forma adjustments based on available information and certain assumptions we believe are reasonable, including (i) adjustments related to the depreciation and amortization of the step up to fair value of $77.6 million for acquired intangibles, $74.4 million for acquired drill bits classified as long-lived assets, and $5.5 million for acquired drill bits classified as inventory, (ii) removal of $12.8 million in 2023 and $28.1 million in 2022 of historical interest expense of the acquired entity and (iii) $17.4 million in 2023 and $11.3 million in 2022 of tax benefit relating to the aforementioned pro forma adjustments.
The pro forma results of operations do not include any anticipated cost savings or other synergies that may result from the Ulterra acquisition nor do they include any estimated costs that will be incurred to integrate Ulterra operations. The pro forma results of operations include our merger and integration expense of $5.6 million as if they had been incurred in the first quarter of 2022.
The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Ulterra acquisition taken place on January 1, 2022. Furthermore, the financial information is not intended to be a projection of future results. The following table summarizes our selected financial information on a pro forma basis (in thousands, except per share data):

| 2023 |  | 2022
| (Unaudited)
Revenues | $ | 4,369,596 |  |  | $ | 3,017,778 |
Net income | $ | 190,136 |  |  | $ | 141,458 |

NexTier Oilfield Solutions Inc.
On September 1, 2023, we completed the NexTier merger. Under the terms of the merger agreement, NexTier became our wholly-owned subsidiary. Each share of NexTier common stock issued and outstanding immediately prior to the effective time of the merger was converted into the right to receive 0.752 shares of our common stock. Additionally, certain equity awards that were granted and outstanding under NexTier long-term incentive plans were assumed by us, and such equity awards were converted into equity awards in respect of our common stock in accordance with the merger agreement.
NexTier is a predominately U.S. land-focused oilfield service provider, with a diverse set of well completion and production services across a variety of active basins.
The total fair value of the consideration transferred was determined as follows (in thousands, except exchange ratio and stock price):

Number of shares of NexTier common stock outstanding as of September 1, 2023 | 228,846
Multiplied by the exchange ratio | 0.752
Number of shares of Patterson-UTI Energy, Inc. common stock issued in connection with the merger | 172,092
Patterson-UTI Energy, Inc. common stock price on September 1, 2023 | $ | 14.91 |
Common stock equity consideration | 2,565,895 |
Acceleration of RSU awards | 1,997 |
Fair value of replacement equity awards (1) | 70,416 |
NexTier long-term debt repaid by Patterson-UTI Energy, Inc. | 161,000 |
Consideration transferred | $ | 2,799,308 |

(1)In connection with the merger, each of the share-based awards held by legacy NexTier employees were replaced with our share-based awards on the merger date. The fair value of the replacement awards has been allocated between each employee’s pre-combination and post-combination services. Amounts allocated to pre-combination services have been included as consideration transferred as part of the merger. See Note 12 for replacement awards details.
The transaction was accounted for as a business combination using the acquisition method with Patterson-UTI Energy, Inc. determined to be the acquirer. Under the acquisition method of accounting, the fair value of the consideration transferred is allocated to the tangible and intangible assets acquired and the liabilities assumed based on their estimated fair values as of the acquisition date.
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The aggregate purchase price noted above was allocated to the major categories of assets acquired and liabilities assumed based on preliminary estimated fair values as of the date of the business combination. We applied significant judgment in estimating the fair value of assets acquired and liabilities assumed, which involved the use of significant estimates and assumptions with respect to future rig counts, cash flow projections, estimated economic useful lives, operating and capital cost estimates, customer attrition rates, contributory asset charges, royalty rates and discount rate (14.0%). The carrying amounts of cash and cash equivalents, accounts receivable, inventory, other assets, accounts payable, accrued liabilities, and other liabilities approximate their fair values due to their nature or the short-term maturity of instruments. The remaining assets acquired and liabilities assumed are based on inputs that are not observable in the market and thus represent Level 3 inputs. The fair value of property and equipment was determined using a combination of replacement cost and indirect cost. Intangible assets were valued using an income approach. The fair value was estimated by using multi-period excess earnings method for customer relationships and a relief from royalty method for trade name and developed technology. The purchase price allocation was finalized in the third quarter of 2024. The valuation period adjustments did not have a material impact on our consolidated financial statements.
The following table summarizes the fair values of the assets acquired and liabilities assumed at the date of the merger:

Assets acquired: |
Cash and cash equivalents | $ | 95,815 |
Accounts receivable | 420,200 |
Inventory | 71,930 |
Property and equipment (1) | 1,045,610 |
Intangible assets | 768,000 |
Operating lease right of use asset | 19,091 |
Finance lease right of use asset | 50,733 |
Other assets | 84,677 |
Total assets acquired | 2,556,056 |
Liabilities assumed: |
Accounts payable | 358,873 |
Accrued liabilities | 129,535 |
Operating lease liability | 19,091 |
Finance lease liability | 50,733 |
Deferred tax liabilities | 86,293 |
Long-term debt | 22,533 |
Other liabilities | 11,815 |
Total liabilities assumed | 678,873 |
Net assets acquired | 1,877,183 |
Goodwill | 922,125 |
Total consideration transferred | $ | 2,799,308 |

(1)We recorded an adjustment of $263 million to write-up acquired property and equipment to estimated fair value. This adjustment will be depreciated on a straight-line basis over a weighted average period of six years .
The goodwill recognized in the merger represents the excess of the gross consideration transferred over the fair value of the underlying net tangible and identifiable intangible assets acquired and liabilities assumed. Goodwill largely consisted of the expected synergies and economies of scale from the combined operations of Patterson-UTI and NexTier as well as the recognition of deferred taxes for the difference between the fair value of the assets acquired and liabilities assumed and the respective carry-over tax basis. All of the goodwill was assigned to our completion services segment. See Note 7.
Approximately $1.1 billion of revenues and $12.5 million of net income attributed to the NexTier merger are included in the consolidated statements of operations for the period from the closing date on September 1, 2023 through December 31, 2023. During the twelve months ended December 31, 2024 and 2023, we incurred costs related to the NexTier merger totaling $28.7 million and $92.5 million, respectively, which are included in our consolidated statements of operations as “Merger and integration expense.”
A portion of the fair value consideration transferred has been provisionally assigned to identifiable intangible assets as follows:
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| Fair Value (in thousands) |  | Weighted Average Useful Life (in years)
Customer relationships | $ | 540,000 |  |  | 10
Trade name | 85,000 |  |  | 10
Developed technology | 143,000 |  |  | 5
Intangible assets | $ | 768,000 |  |  |

Pro Forma
The following pro forma condensed combined financial information was derived from our and NexTier's historical financial statements and gives effect to the acquisition as if it had occurred on January 1, 2022. The below information reflects pro forma adjustments based on available information and certain assumptions we believe are reasonable, including (i) adjustments related to the depreciation and amortization of the step up to fair value of $720.7 million for acquired intangibles and $262.7 million for acquired property and equipment, (ii) removal of $17.7 million in 2023 and $30.0 million in 2022 of historical interest expense of the acquired entity and (iii) $15.1 million in 2023 and $72.7 million of tax benefit in 2022 relating to the aforementioned pro forma adjustments.
The pro forma results of operations do not include any anticipated cost savings or other synergies that may result from the NexTier merger nor do they include any estimated costs that will be incurred to integrate NexTier operations. The pro forma results of operations include our merger and integration expense of $92.5 million as if they had been incurred in the first quarter of 2022.
The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the NexTier merger taken place on January 1, 2022. Furthermore, the financial information is not intended to be a projection of future results. The following table summarizes our selected financial information on a pro forma basis (in thousands, except per share data):

| 2023 |  | 2022
| (Unaudited)
Revenues | $ | 6,604,824 |  |  | $ | 5,892,414 |
Net income | $ | 598,709 |  |  | $ | 196,220 |

3. Revenues
ASC Topic 606 Revenue from Contracts with Customers
Drilling Services and Completion Services — r evenue 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 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 pursuant to contractual arrangements, such as term contracts and 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
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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.
Accounts Receivable and Contract Liabilities
Accounts receivable is our right to consideration once it becomes unconditional. Payment terms typically range from 30 to 60 days.
Accounts receivable balances were $697 million and $900 million as of December 31, 2024 and 2023, respectively. These balances do not include amounts related to our oil and natural gas working interests nor do they include amounts related to our lease revenues under Topic 842 as those contracts are excluded from Topic 606. Accounts receivable balances are included in “Accounts receivable” in our consolidated balance sheets.
We do not have any significant contract asset balances. Contract liabilities include prepayments received from customers prior to the requested services being completed. Once the services are complete and have been invoiced, the prepayment is applied against the customer’s account to offset the accounts receivable balance. Also included in contract liabilities are payments received from customers for 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 $75.6 million and $103 million as of December 31, 2024 and December 31, 2023, respectively. In 2024, we recognized $102 million of revenue 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. In 2023, we recognized $136 million of revenue that was included in the contract liability balance at the beginning of the period, of which the recognition of $28.9 million was due to deferred revenue from a customer prepayment, which became recognizable after the customer changed its drilling schedule. The $75.2 million current portion of our contract liability balance is included in “Accrued liabilities” and $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.
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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 December 31, 2024 was approximately $426 million. Approximately 7.1% of our total contract drilling backlog in the United States at December 31, 2024 is reasonably expected to remain at December 31, 2025. 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 December 31, 2024. 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 this Report.
4. Inventory
Inventory consisted of the following at December 31, 2024 and 2023 (in thousands):

| 2024 |  | 2023
Raw materials and supplies | $ | 121,694 |  |  | $ | 141,311 |
Work-in-process | 6,681 |  |  | 7,437 |
Finished goods | 38,648 |  |  | 32,057 |
Inventory | $ | 167,023 |  |  | $ | 180,805 |

5. Other Current Assets
Other current assets consisted of the following at December 31, 2024 and 2023 (in thousands):

| 2024 |  | 2023
Federal and state income taxes receivable | $ | 24,777 |  |  | $ | 26,949 |
Workers’ compensation receivable | 33,240 |  |  | 31,006 |
Prepaid expenses | 34,004 |  |  | 46,394 |
Other | 31,172 |  |  | 36,773 |
Other current assets | $ | 123,193 |  |  | $ | 141,122 |

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6. Property and Equipment
Property and equipment consisted of the following at December 31, 2024 and 2023 (in thousands):

| 2024 |  | 2023
Equipment | $ | 8,416,063 |  |  | $ | 8,506,727 |
Oil and natural gas properties | 243,663 |  |  | 238,337 |
Buildings | 248,739 |  |  | 248,693 |
Rental equipment | 136,256 |  |  | 119,653 |
Land | 37,847 |  |  | 38,811 |
Total property and equipment | 9,082,568 |  |  | 9,152,221 |
Less accumulated depreciation, depletion, amortization and impairment | (6,072,226) |  |  | (5,811,809) |
Property and equipment, net | $ | 3,010,342 |  |  | $ | 3,340,412 |

Depreciation, depletion, amortization and impairment — The following table summarizes depreciation, depletion, amortization and impairment expense related to property and equipment and intangible assets for 2024, 2023 and 2022 (in thousands):

| 2024 |  | 2023 |  | 2022
Depreciation and impairment expense | $ | 1,039,536 |  |  | $ | 682,672 |  |  | $ | 472,969 |
Amortization expense | 124,716 |  |  | 41,521 |  |  | 2,891 |
Depletion expense | 7,621 |  |  | 7,223 |  |  | 8,085 |
Total | $ | 1,171,873 |  |  | $ | 731,416 |  |  | $ | 483,945 |

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 respective asset or 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.
Negative market indicators such as lower industry-wide drilling rig count forecasts, increased volatility and pricing declines in the pressure pumping market, and continued efficiency gains and technology advancements reducing operating days have led to our reduced outlook for activity. The reduction in activity forecasts, the recent 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 intangible assets may be 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.
We also evaluated our fleet of drilling rigs for marketability based on the condition of inactive rigs, expenditures that would be necessary to bring them to working condition and the expected demand for drilling services by rig type. The components comprising rigs that will no longer be marketed were evaluated, and those components with continuing utility to other marketed rigs were identified for transfer to other rigs or to yards to be used as spare equipment. The remaining components of these rigs were abandoned. During the third quarter of 2024, we identified 42 legacy, non-Tier-1 super-spec drilling rigs and related equipment to be abandoned. Based on the strong customer preference across the industry for Tier-1 super-spec drilling rigs, in addition to efficiency gains and technology advancements that have reduced the total number of rigs needed for the U.S. drilling market, we believe the 42 rigs that were abandoned had limited commercial opportunity. Accordingly, we recorded a charge of $114 million related to this abandonment in 2024. No similar charges were incurred in 2022 or 2023.
We also periodically evaluate our other tangible long-lived assets for marketability based on the condition of inactive equipment, expenditures that would be necessary to bring the equipment to working condition and the expected demand for such equipment. The components of equipment that will no longer be marketed are evaluated, and those components with continuing utility will be used as
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parts to support active equipment. The remaining components of this equipment are abandoned. There were no material abandonments in 2022, 2023 or 2024 except for the aforementioned 42 legacy, non-Tier-1 super spec drilling rigs and related equipment.
Geopolitical instability, global or regional decreases in the demand of our services and products, or other unforeseen macroeconomic considerations could negatively impact the expected cash flows used in our recoverability tests on 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.
7. Goodwill and Intangible Assets
Goodwill — 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 the Ulterra acquisition was allocated to that reporting unit. We determined our completion services operating segment consists of two reporting units; completion services, which is primarily comprised of our hydraulic fracturing operations and other integrated service offerings, and cementing services.
Goodwill Impairment Assessment
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 have led to our reduced outlook for activity. During the third quarter of 2024, we viewed the reduction in activity forecasts combined with the decline in the market price of our common stock as a triggering event that warranted a quantitative assessment for goodwill impairment.
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.
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.
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 will persist 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.
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Based on the results of the goodwill impairment tests performed during the third quarter of 2024, the fair values of the drilling products and cementing services reporting units exceeded their carrying values by approximately 13% and 73%, respectively. Accordingly, no impairment was recorded for the drilling products and cementing services reporting units.
Goodwill by operating segment as of December 31, 2023 and 2024 and changes for the years then ended are as follows (in thousands):

| Completion Services |  | Drilling Products |  | Total
Balance, December 31, 2023 | $ | 922,125 |  |  | $ | 457,616 |  |  | $ | 1,379,741 |
Measurement period adjustment | — |  |  | (7,113) |  |  | (7,113) |
Impairment | (885,240) |  |  | — |  |  | (885,240) |
Balance, December 31, 2024 | $ | 36,885 |  |  | $ | 450,503 |  |  | $ | 487,388 |

Intangible Assets — Our intangible assets were recorded at fair value on the date of acquisition and are amortized on a straight-line basis. The following table identifies the segment and weighted average useful life of each of our intangible assets:

| Segment |  | Weighted Average Useful Life
|  |  | (in years)
Customer relationships | Drilling Services, Completion Services and Drilling Products |  | 11.5
Developed technology | Drilling Services, Completion Services and Drilling Products |  | 5.2
Trade name | Completion Services and Drilling Products |  | 10.2
Other | Drilling Services and Completion Services |  | 3.1

The gross carrying amount and accumulated amortization of intangible assets as of December 31, 2024 and 2023 are as follows (in thousands):

| 2024 |  | 2023
| Gross Carrying Amount |  | Accumulated Amortization |  | Net Carrying Amount |  | Gross Carrying Amount |  | Accumulated Amortization |  | Net Carrying Amount
Customer relationships | $ | 782,789 |  |  | $ | (95,785) |  |  | $ | 687,004 |  |  | $ | 786,715 |  |  | $ | (25,563) |  |  | $ | 761,152 |
Developed technology | 202,772 |  |  | (56,562) |  |  | 146,210 |  |  | 202,772 |  |  | (16,435) |  |  | 186,337 |
Trade name | 101,000 |  |  | (14,097) |  |  | 86,903 |  |  | 101,000 |  |  | (3,406) |  |  | 97,594 |
Other | 12,986 |  |  | (3,493) |  |  | 9,493 |  |  | 7,345 |  |  | (731) |  |  | 6,614 |
Intangible assets, net | $ | 1,099,547 |  |  | $ | (169,937) |  |  | $ | 929,610 |  |  | $ | 1,097,832 |  |  | $ | (46,135) |  |  | $ | 1,051,697 |

Amortization expense on intangible assets of approximately $124 million, $41.5 million, and $1.3 million was recorded for the years ended December 31, 2024, 2023 and 2022, respectively.
The remaining amortization expense associated with finite-lived intangible assets, excluding in-process software, is expected to be as follows (in thousands):

Year ending December 31, |
2025 | $ | 123,645 |
2026 | 123,277 |
2027 | 121,250 |
2028 | 105,236 |
2029 | 80,068 |
Thereafter | 373,535 |
Total | $ | 927,011 |

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8. Accrued Liabilities
Accrued liabilities consisted of the following at December 31, 2024 and 2023 (in thousands):

| 2024 |  | 2023
Salaries, wages, payroll taxes and benefits | $ | 110,212 |  |  | $ | 129,982 |
Workers’ compensation liability | 73,730 |  |  | 67,396 |
Property, sales, use and other taxes | 54,445 |  |  | 62,194 |
Insurance, other than workers’ compensation | 10,703 |  |  | 11,524 |
Accrued interest payable | 17,484 |  |  | 19,172 |
Deferred revenue | 75,195 |  |  | 98,914 |
Federal and state income taxes payable | — |  |  | 3,437 |
Accrued merger and integration expense | 4,723 |  |  | 15,113 |
Other | 39,259 |  |  | 38,536 |
Accrued liabilities | $ | 385,751 |  |  | $ | 446,268 |

9. Long-Term Debt
Long-term debt consisted of the following at December 31, 2024 and 2023 (in thousands):

| Effective Interest Rate |  | December 31, 2024 |  | December 31, 2023
3.95% Senior Notes Due 2028 | 4.03% |  | $ | 482,505 |  |  | $ | 482,505 |
5.15% Senior Notes Due 2029 | 5.26% |  | 344,895 |  |  | 344,895 |
7.15% Senior Notes Due 2033 | 7.28% |  | 400,000 |  |  | 400,000 |
Equipment Loans Due 2025 | 5.25% |  | 6,395 |  |  | 18,686 |
|  |  | 1,233,795 |  |  | 1,246,086 |
Less deferred financing costs and discounts |  |  | (7,637) |  |  | (8,919) |
Less current portion |  |  | (6,388) |  |  | (12,226) |
Total |  |  | $ | 1,219,770 |  |  | $ | 1,224,941 |

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. For a description of the Credit Agreement, see “Liquidity and Capital Resources” included in Part II, Item 7— “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Report.
On April 5, 2024, we entered into a Commitment Increase Agreement (the “Commitment Increase Agreement”), which increased the commitments under our Amended and Restated Credit Agreement, dated as of March 27, 2018 (as modified by the Commitment Increase Agreement and amended to date, the “Prior Credit Agreement”), by and among us, as borrower, Wells Fargo Bank, National Association, as administrative agent, letter of credit issuer, swing line lender and lender and each of the other letter of credit issuers and lenders party thereto.
The Commitment Increase Agreement increased the commitments under our Prior Credit Agreement to $615 million. The maturity date for $567 million of such commitments was March 27, 2026; and the maturity date for $48.3 million of such commitments was March 27, 2025.
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On August 29, 2023, we entered into Amendment No. 4 to Amended and Restated Credit Agreement (the “Credit Agreement Amendment”), which, among other things, extended the maturity date for $85.0 million of revolving credit commitments of certain lenders under the Prior Credit Agreement from March 27, 2025 to March 27, 2026.
The Prior Credit Agreement is a committed senior unsecured revolving credit facility that permits aggregate borrowings of up to $615 million, including a letter of credit facility that, at any time outstanding, is limited to $100 million and a swing line facility that, at any time outstanding, is limited to the lesser of $50.0 million and the amount of the swing line provider’s unused commitment.
Loans under the Prior Credit Agreement bear interest by reference, at our election, to the SOFR rate (subject to 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 1.00% to 2.00% and the applicable margin on base rate loans varies from 0.00% to 1.00%, in each case determined based on our credit rating. As of December 31, 2024, 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 0.10% to 0.30% based on our credit rating.
None of our subsidiaries are currently required to be a guarantor under the Prior 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 Prior Credit Agreement), such subsidiary is required to become a guarantor under the Prior Credit Agreement.
The Prior 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 Prior 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 Prior 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 Prior 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 December 31, 2024.
As of December 31, 2024, we had no borrowings outstanding under our revolving credit facility. We had $2.1 million in letters of credit outstanding under the Prior Credit Agreement at December 31, 2024 and, as a result, had available borrowing capacity of approximately $613 million 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 December 31, 2024, 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.
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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 our 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 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 December 31, 2024 (in thousands):

Year ending December 31, |
2025 | $ | 6,395 |
2026 | — |
2027 | — |
2028 | 482,505 |
2029 | 344,895 |
Thereafter | 400,000 |
Total | $ | 1,233,795 |

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10. Commitments and Contingencies
Commitments – As of December 31, 2024, we maintained letters of credit in the aggregate amount of $42.9 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 December 31, 2024, no amounts had been drawn under the letters of credit. As of December 31, 2024, we had $35.0 million in surety bond exposure issued as financial assurance on an insurance agreement.
As of December 31, 2024, we had commitments to purchase major equipment totaling approximately $65.9 million.
Our completion services segment has entered into agreements to purchase minimum quantities of proppants from certain vendors. We purchased $103 million, $135 million and $93.0 million of proppants under take-or-pay or similar agreements during the years ended December 31, 2024, 2023 and 2022, respectively. As of December 31, 2024, the remaining minimum obligation under these agreements was approximately $19.8 million, of which approximately, $17.4 million and $2.4 million relate to 2025 and 2026, respectively.
Contingencies – Our operations are subject to many hazards inherent in the businesses in which we operate, including inclement weather, blowouts, explosions, fires, loss of well control, motor vehicle accidents, equipment failure, unplanned power outages and surges, computer system disruptions or cybersecurity incidents, pollution, exposure and reservoir damage. These hazards could cause personal injury or death, work stoppage, and serious damage to equipment and other property, as well as significant environmental and reservoir damages. These risks could expose us to substantial liability for personal injury, wrongful death, property damage, loss of oil and natural gas production, pollution and other environmental damages. An accident or other event resulting in significant environmental or property damage, or injuries or fatalities involving our employees or other persons could also trigger investigations by federal, state or local authorities. Such an accident or other event could cause us to incur substantial expenses in connection with the investigation, remediation and resolution, as well as cause lasting damage to our reputation, loss of customers and an inability to obtain insurance.
We have indemnification agreements with many of our customers, and we also maintain liability and other forms of insurance. In general, our contracts typically contain provisions requiring our customers to indemnify us for, among other things, reservoir and certain pollution damage. Our right to indemnification may, however, be unenforceable or limited due to negligent or willful acts or omissions by us, our subcontractors and/or suppliers. In addition, certain states, including Louisiana, New Mexico, Texas and Wyoming, have enacted statutes generally referred to as “oilfield anti-indemnity acts” expressly prohibiting certain indemnity agreements contained in or related to oilfield services agreements. Such oilfield anti-indemnity acts may restrict or void a party’s indemnification of us.
Our customers and other third parties may dispute, or be unable to meet, their indemnification obligations to us due to financial, legal or other reasons. Accordingly, we may be unable to transfer these risks to our customers and other third parties by contract or indemnification agreements. Incurring a liability for which we are not fully indemnified or insured could have a material adverse effect on our business, financial condition, cash flows and results of operations.
In addition, we maintain insurance coverage of the types and in the amounts we believe to be customary in the industry, but we do not insure against all risks, either because insurance is not available or because it is not commercially justifiable. The insurances that we maintain include coverage for fire, windstorm and other risks of physical loss to our equipment and certain other assets, employers’ liability, automobile liability, commercial general liability, workers’ compensation as well as insurance for other specific risks, together with excess loss liability insurance coverage. We have also elected to retain a greater amount of risk through increased deductibles as compared to prior years, or self-insurance on certain insurance policies. We cannot assure that any insurance obtained by us will be adequate to cover any losses or liabilities nor can we assure that any insurance obtained by us will continue to be made available for purchase or made available on acceptable terms. While we carry insurance to cover physical damage to, or loss of, a substantial portion of our equipment and certain other assets, such insurance does not cover the full replacement cost of such equipment or other assets, and in certain cases, such as losses arising from or attributable to fire and/or explosion resulting from our hydraulic fracturing operations at the wellsite, is subject to significantly higher deductibles than are applicable to our other coverages. We also self-insure a number of risks, including loss of earnings and business interruption and most of our cybersecurity risks, and we do not carry a significant amount of insurance to cover risks of underground reservoir damage.
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.
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The case is Grant Prideco, Inc., et al. v. Schlumberger Technology Corp., et al., in Texas State Court, District of Harris County, 11th Judicial District. 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. 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.
Discovery is closed and dispositive motions are scheduled to be fully briefed by the end of March 2025. Trial is currently scheduled for March 31, 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 legal proceedings arising in the normal course of our business. We do not believe that the outcome of these proceedings, either individually or in the aggregate, will have a material adverse effect on our financial condition, cash flows and results of operations.
11. Stockholders’ Equity
Cash Dividend — On February 5, 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 March 17, 2025 to holders of record as of March 3, 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 December 31, 2024, we had remaining authorization to purchase approximately $759 million of our outstanding common stock under the stock buyback program. Shares of stock purchased under the buyback program are held as treasury shares.
We acquired shares of stock from employees during 2024, 2023 and 2022 that are accounted for as treasury stock. Certain of these shares were acquired to satisfy the exercise price and employees’ tax withholding obligations upon the exercise of stock options. The remainder of these shares were acquired to satisfy payroll withholding obligations upon the settlement of performance unit awards and the vesting of restricted stock units. These shares were acquired at fair market value. These acquisitions were made pursuant to the terms of the Patterson-UTI Energy, Inc. Amended and Restated 2014 Long-Term Incentive Plan, as amended (the “2014 Plan”), the Patterson-UTI Energy, Inc. 2021 Long-Term Incentive Plan (the “2021 Plan”), the NexTier Oilfield Solutions Inc. Equity and Incentive Award Plan and the NexTier Oilfield Solutions Inc. (Former C&J Energy) Management Incentive Plan, and not pursuant to the stock buyback program.
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Treasury stock acquisitions during the years ended December 31, 2024, 2023 and 2022 were as follows (dollars in thousands):

| 2024 |  | 2023 |  | 2022
| Shares |  | Cost |  | Shares |  | Cost |  | Shares |  | Cost
Treasury shares at beginning of period | 105,580,011 |  | $ | 1,657,675 |  |  | 88,758,722 |  | $ | 1,453,079 |  |  | 84,128,995 |  | $ | 1,372,641 |
Purchases pursuant to stock buyback program | 26,646,698 |  | 280,327 |  |  | 14,086,229 |  | 168,631 |  |  | 3,254,599 |  | 57,173 |
Acquisitions pursuant to long-term incentive plan | 1,213,319 |  | 13,065 |  |  | 2,735,060 |  | 35,965 |  |  | 1,372,101 |  | 23,237 |
Other | — |  | — |  |  | — |  |  | — |  |  | 3,027 |  | 28 |
Treasury shares at end of period | 133,440,028 |  | $ | 1,951,067 |  |  | 105,580,011 |  | $ | 1,657,675 |  |  | 88,758,722 |  | $ | 1,453,079 |

12. 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.
The 2021 Plan was originally approved by our stockholders on June 3, 2021. Our Board of Directors and our stockholders have approved a series of amendments to the 2021 Plan (the “2021 Plan Amendments”) to increase the number of shares available for issuance under the 2021 Plan. Following the 2021 Plan Amendments, the aggregate number of shares of Common Stock authorized for grant under the 2021 Plan is approximately 39.1 million.
On September 1, 2023, the Board of Directors also approved amendments to the NexTier Plan and the NexTier Oilfield Solutions Inc. (Former C&J Energy) Management Incentive Plan (the “Former C&J Energy Plan” and, together with the NexTier Plan, the “Assumed Plans”) to assume awards that were previously granted under the Assumed Plans (consisting of stock options, time- and performance-based restricted stock units and cash-settled performance unit awards), which, in connection with the NexTier merger, were converted into share-based awards in respect of shares of Patterson-UTI Energy, Inc. common stock.
Our share-based compensation plans at December 31, 2024 are as follows:

Plan Name |  | Shares Authorized for Grant |  | Shares Underlying Awards Outstanding |  | Shares Available for Grant
2021 Plan |  | 39,074,510 |  | 6,440,885 |  | 17,520,596
NexTier Plan |  | — |  | 977,011 |  | —
Former C&J Energy Plan |  | — |  | 406,405 |  | —
2014 Plan |  | — |  | 1,719,275 |  | —

Stock Options — We estimate the grant date fair values of stock options using the Black-Scholes-Merton valuation model. Volatility assumptions are based on the historic volatility of our common stock over the most recent period equal to the expected term of the options as of the date such options are granted. The expected term assumptions are based on our experience with respect to employee stock option activity. Dividend yield assumptions are based on the expected dividends at the time the options are granted.
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The risk-free interest rate assumptions are determined by reference to United States Treasury yields. No options were granted during the years ended December 31, 2024, 2023 and 2022.
Stock option activity for the year ended December 31, 2024 follows:

| Shares |  | Weighted Average Exercise Price Per Share
Outstanding at beginning of year | 2,865,223 |  | $ | 23.36 |
Exercised | — |  | $ | — |
Expired | (1,071,218) |  | $ | 25.19 |
Outstanding at end of year | 1,794,005 |  | $ | 22.26 |
Exercisable at end of year | 1,794,005 |  | $ | 22.26 |

Options outstanding and exercisable at December 31, 2024 have no intrinsic value and a weighted-average remaining contractual term of 1.20 years. Additional information with respect to options granted, vested and exercised during the years ended December 31, 2024, 2023 and 2022 follows (in thousands, except per share data):

| 2024 |  | 2023 |  | 2022
Weighted-average grant date fair value of stock options granted (per share) | NA |  | NA |  | NA
Aggregate grant date fair value of stock options vested during the year | $ | — |  |  | $ | — |  |  | $ | — |
Aggregate intrinsic value of stock options exercised | $ | — |  |  | $ | — |  |  | $ | 410 |

As of December 31, 2024, no options to purchase shares were outstanding and unvested.
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 for the year ended December 31, 2024 follows:

| Time Based |  | Performance Based |  | Weighted Average Grant Date Fair Value Per Share
Non-vested restricted stock units outstanding at beginning of year | 5,827,668 |  | 521,533 |  | $ | 10.60 |
Granted | 3,113,411 |  | — |  | $ | 10.49 |
Vested | (3,245,228) |  | (45,661) |  | $ | 9.11 |
Forfeited | (268,194) |  | (23,358) |  | $ | 11.33 |
Non-vested restricted stock units outstanding at end of year | 5,427,657 |  | 452,514 |  | $ | 11.34 |

As of December 31, 2024, approximately 5.5 million non-vested restricted stock units outstanding are expected to vest. Additional information as of December 31, 2024 with respect to these non-vested restricted stock units follows (dollars in thousands):

Aggregate intrinsic value | $ | 45,167 |
Weighted-average remaining vesting period | 1.71 years
Unrecognized compensation cost | $ | 42,828 |

Restricted Stock Units (Liability Based) — We converted NexTier’s cash-settled performance based units into our cash-settled restricted stock units in connection with the NexTier merger. These awards are accounted for as liability classified awards and remeasured at fair value at each reporting period. Compensation expense is recorded over the vesting period and is initially based on the fair value at the award conversion date. Compensation expense is 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. As of December 31, 2024, $3.3 million is included in “Accrued liabilities” in our consolidated balance sheets for these awards. We recognized $0.6 million of compensation expense for these awards during the year ended December 31, 2024.
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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 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 years 2019-2024 is set forth below:

| 2024 Performance Unit Awards |  | 2023 Performance Unit Awards |  | 2022 Performance Unit Awards |  | 2021 Performance Unit Awards |  | 2020 Performance Unit Awards |  | 2019 Performance Unit Awards
Target number of shares | 875,100 |  | 631,700 |  | 414,000 |  | 843,000 |  | 500,500 |  | 489,800

In April 2022, 979,600 shares were issued to settle the 2019 Performance Units. In May 2023, 1,001,000 shares were issued to settle the 2020 Performance Units. In May 2024, 718,581 shares were issued to settle the 2021 Performance Units. The Performance Units granted in 2022, 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):
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| 2024 Performance Unit Awards |  | 2023 Performance Unit Awards |  | 2022 Performance Unit Awards |  | 2021 Performance Unit Awards |  | 2020 Performance Unit Awards |  | 2019 Performance Unit Awards
Aggregate fair value at date of grant | $ | 10,904 |  |  | $ | 8,440 |  |  | $ | 10,743 |  |  | $ | 7,225 |  |  | $ | 826 |  |  | $ | 9,958 |

The weighted-average fair value calculations for performance units granted during the years ended December 31, 2024, 2023 and 2022 were based on the following weighted-average assumptions set forth below:

| 2024 |  | 2023 |  | 2022
Risk-free interest rate (1) | 4.6 | % |  | 3.6 | % |  | 2.9 | %
Expected stock volatility (2) | 56.9 | % |  | 72.1 | % |  | 86.5 | %
Expected dividend yield (3) | 2.9 | % |  | 3.0 | % |  | 1.0 | %
Expected term (in years) | 3 |  | 3 |  | 3

(1)The risk-free interest rate is based on U.S. Treasury securities for the expected term of the Performance Units.
(2)Expected volatilities are based on the daily closing price of our stock based upon historical experience over a three-year period.
(3)Expected dividend yield is based on the annualized dividend in effect on the measurement date and the stock price on the grant date.
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 |  | 2020 Performance Unit Awards |  | 2019 Performance Unit Awards
Year ended December 31, 2024 | $ | 2,436 |  |  | $ | 2,665 |  |  | $ | 3,459 |  |  | $ | 584 |  |  | NA |  | NA
Year ended December 31, 2023 | NA |  | $ | 2,248 |  |  | $ | 3,749 |  |  | $ | 2,426 |  |  | $ | 69 |  |  | NA
Year ended December 31, 2022 | NA |  | NA |  | $ | 2,686 |  |  | $ | 2,408 |  |  | $ | 275 |  |  | $ | 830 |

As of December 31, 2024, we had unrecognized compensation cost of $12.8 million related to our unvested Performance Units. The weighted-average remaining vesting period for these unvested Performance Units was 1.04 years as of December 31, 2024.
Dividends on Equity Awards — Dividend equivalents are paid or accrued on certain restricted stock units. These dividends are recognized as reductions of retained earnings for the portion of restricted stock units expected to vest.
Phantom Units — In May 2020, the Compensation Committee approved a grant of long-term performance-based phantom units to our Chief Executive Officer and President, William A. Hendricks, Jr. (the “Phantom Units”). The Phantom Units were granted outside of the 2014 Plan. Pursuant to this phantom unit grant, Mr. Hendricks could earn from 0% to 200% of a target award of 298,500 phantom units based on our achievement of the same performance conditions over the same performance period that applied to the Performance Units granted in April 2020. The Phantom Units settled in May 2023, with a cash payment of $7.4 million.
13. Leases
ASC Topic 842 Leases
We have operating and finance leases primarily for office locations, including for both field locations and corporate offices, certain operating equipment, and light duty vehicles. The terms and conditions for these leases vary by the type of underlying asset.
During the third quarter of 2023, we acquired $7.5 million and $19.1 million of operating leases for operating locations, corporate offices, certain operating equipment and light duty vehicles primarily related to the Ulterra acquisition and NexTier merger, respectively.
We also acquired $5.2 million and $50.7 million of finance leases for light duty vehicles and certain operating equipment related to the Ulterra acquisition and NexTier merger, respectively.
Operating leases have remaining lease terms of approximately one month to ten years as of December 31, 2024, and finance leases have remaining lease terms of approximately one month to six years as of December 31, 2024.
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Lease expense consisted of the following for the years ended December 31, 2024, 2023 and 2022 (in thousands):

| Year Ended December 31,
| 2024 |  | 2023 |  | 2022
Operating lease cost | $ | 18,147 |  |  | $ | 10,073 |  |  | $ | 5,664 |
Finance lease cost: |  |  |  |  |
Amortization of right-of-use assets | 21,394 |  |  | 6,360 |  |  | — |
Interest on lease liabilities | 2,255 |  |  | 1,395 |  |  | — |
Total finance lease cost | 23,649 |  |  | 7,755 |  |  | — |
Short-term lease expense (1) | 360 |  |  | 2,278 |  |  | — |
Total lease expense (2) | $ | 42,156 |  |  | $ | 20,106 |  |  | $ | 5,664 |

(1)Short-term lease expense represents expense related to leases with a contract term of one year or less.
(2)Operating lease expense is recorded in operating costs for the respective segments and within “selling, general and administrative”, amortization of right-of-use assets is recorded within “depreciation, depletion, amortization and impairment”, and interest on lease liabilities is recorded within “interest expense” in our consolidated statements of operations.
Supplemental cash flow information related to leases for the years ended December 31, 2024, 2023 and 2022 is as follows (in thousands):

| Year Ended December 31,
| 2024 |  | 2023 |  | 2022
Cash paid for amounts included in the measurement of lease liabilities: |  |  |  |  |
Operating cash flows from operating leases | $ | 14,838 |  |  | $ | 8,935 |  |  | $ | 6,858 |
Operating cash flows from finance leases | 2,220 |  |  | 1,380 |  |  | — |
Financing cash flows from finance leases | 45,484 |  |  | 15,915 |  |  | — |
Right of use assets obtained in exchange for lease obligations: |  |  |  |  |
Operating leases (1) | $ | 12,541 |  |  | $ | 34,802 |  |  | $ | 6,530 |
Finance leases (1) | 21,234 |  |  | 73,245 |  |  | — |

(1)Includes right of use assets acquired in business combinations in 2023.
Lease terms and discount rates related to leases as of December 31, 2024 and 2023 is as follows:

| 2024 |  | 2023
Weighted Average Remaining Lease Term: |  |  |
Operating leases | 4.8 years |  | 5.0 years
Finance leases | 2.3 years |  | 1.5 years
Weighted Average Discount Rate: |  |  |
Operating leases | 6.5 | % |  | 6.1 | %
Finance leases | 7.4 | % |  | 7.3 | %

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Maturities of operating and finance lease liabilities as of December 31, 2024 are as follows (in thousands):

Year ending December 31, | Operating |  | Finance
2025 | $ | 15,791 |  |  | $ | 16,664 |
2026 | 11,692 |  |  | 6,264 |
2027 | 8,238 |  |  | 1,490 |
2028 | 6,700 |  |  | 1,485 |
2029 | 5,904 |  |  | 1,485 |
Thereafter | 6,944 |  |  | 595 |
Total lease payments | 55,269 |  |  | 27,983 |
Less imputed interest | (7,642) |  |  | (2,553) |
Total | $ | 47,627 |  |  | $ | 25,430 |

14. Income Taxes
Income (loss) before income taxes for the United States and non-U.S. jurisdictions for the years ended December 31, 2024, 2023, and 2022 are as follows (in thousands):

| 2024 |  | 2023 |  | 2022
Income (loss) before income taxes: |  |  |  |  |
United States | $ | (946,388) |  |  | $ | 315,897 |  |  | $ | 165,878 |
Non-U.S. | (10,558) |  |  | (8,793) |  |  | 1,984 |
| $ | (956,946) |  |  | $ | 307,104 |  |  | $ | 167,862 |

Components of the income tax provision applicable to federal, state and foreign income taxes for the years ended December 31, 2024, 2023 and 2022 are as follows (in thousands):

| 2024 |  | 2023 |  | 2022
Federal income tax expense (benefit): |  |  |  |  |
Current | $ | 417 |  |  | $ | — |  |  | $ | 480 |
Deferred | (1,390) |  |  | 44,369 |  |  | 11,820 |
| (973) |  |  | 44,369 |  |  | 12,300 |
State income tax expense (benefit): |  |  |  |  |
Current | 4,882 |  |  | 7,002 |  |  | 2,647 |
Deferred | (1,412) |  |  | 11,279 |  |  | (4,896) |
| 3,470 |  |  | 18,281 |  |  | (2,249) |
Foreign income tax expense (benefit): |  |  |  |  |
Current | 5,269 |  |  | 1,578 |  |  | 2,750 |
Deferred | 1,687 |  |  | (3,076) |  |  | 403 |
| 6,956 |  |  | (1,498) |  |  | 3,153 |
Total income tax expense (benefit): |  |  |  |  |
Current | 10,568 |  |  | 8,580 |  |  | 5,877 |
Deferred | (1,115) |  |  | 52,572 |  |  | 7,327 |
Total income tax expense | $ | 9,453 |  |  | $ | 61,152 |  |  | $ | 13,204 |

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The differences between the statutory U.S. federal income tax rate and the effective income tax rate for the years ended December 31, 2024, 2023 and 2022 are summarized as follows:

| 2024 |  | 2023 |  | 2022
Statutory tax rate | 21.0 | % |  | 21.0 | % |  | 21.0 | %
State income taxes - net of the federal income tax benefit | 0.5 |  | 3.2 |  | 3.0
State deferred tax remeasurement | (0.7) |  | (0.3) |  | 9.4
Goodwill impairment | (19.4) |  | — |  | —
Valuation allowance | (1.3) |  | (9.2) |  | (33.4)
U.S. impact of foreign operations | (0.2) |  | — |  | 1.3
Acquisition related costs | — |  | 1.1 |  | —
Effect of foreign taxes | 0.3 |  | 0.1 |  | 1.6
Non-deductible compensation | (0.7) |  | 1.8 |  | 4.3
Share-based compensation | (0.3) |  | 1.6 |  | (1.9)
Non-deductible expenses | (0.7) |  | 0.7 |  | 1.2
Other differences, net | 0.5 |  | (0.1) |  | 1.4
Effective tax rate | (1.0 | %) |  | 19.9 | % |  | 7.9 | %

Our effective income tax rate fluctuates based on, among other factors, changes in pre-tax income in countries with varying statutory tax rates, changes in valuation allowances, and the impacts of various other permanent adjustments.
The impact of goodwill impairment that is not deductible for income tax had a significant impact on our effective tax rate for the year ended December 31, 2024.
The tax effect of temporary differences and tax attributes representing deferred tax assets and liabilities at December 31, 2024 and 2023 are as follows (in thousands):

| 2024 |  | 2023
Deferred tax assets: |  |  |
Net operating loss carryforwards | $ | 406,876 |  |  | $ | 498,948 |
Tax credits | 17,254 |  |  | 13,488 |
Expense associated with stock options and restricted stock units | 8,344 |  |  | 10,892 |
Workers’ compensation allowance | 9,437 |  |  | 7,024 |
Other deferred tax asset | 79,132 |  |  | 69,480 |
| 521,043 |  |  | 599,832 |
Less: |  |  |
Allowance to reduce deferred tax asset to expected realizable value | (86,693) |  |  | (75,250) |
Total deferred tax assets | 434,350 |  |  | 524,582 |
Deferred tax liabilities: |  |  |
Property and equipment basis difference | (654,541) |  |  | (729,376) |
Other | (17,906) |  |  | (39,386) |
Total deferred tax liabilities | (672,447) |  |  | (768,762) |
Net deferred tax liability | $ | (238,097) |  |  | $ | (244,180) |

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. During 2024, we increased the valuation allowance against our net deferred tax assets by $11.4 million, which primarily related to U.S. state and foreign activity.
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For income tax purposes, we had approximately $1.5 billion of gross U.S. federal net operating losses, approximately $58.7 million of gross Canadian net operating losses and approximately $910 million of post-apportionment U.S. state net operating losses as of December 31, 2024, before valuation allowances. The majority of the U.S. federal net operating losses are generated after 2017 and can be carried forward indefinitely. Canadian net operating losses will expire in varying amounts, if unused, between 2036 and 2044. U.S. state net operating losses will expire in varying amounts, if unused, between 2025 and 2044.
As of December 31, 2024, we have not recognized any liabilities associated with unrecognized tax benefits. We have established a policy to account for interest and penalties related to uncertain income tax positions as operating expenses. As of December 31, 2024, the tax years ended December 31, 2010 through December 31, 2023 are open for examination by U.S. taxing authorities. As of December 31, 2024, the tax years ended December 31, 2017 through December 31, 2023 are open for examination by Canadian taxing authorities. As of December 31, 2024, the tax years ended December 31, 2018 through December 31, 2023 are open for examination by Colombian taxing authorities.
We continue to monitor income tax developments, including OECD Pillar 2 legislation, 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.
15. Earnings Per Share
We provide a dual presentation of our net income (loss) per common share in our 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.
The following table presents information necessary to calculate net income (loss) per share for the years ended December 31, 2024, 2023 and 2022, 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):

| 2024 |  | 2023 |  | 2022
BASIC EPS: |  |  |  |  |
Net income (loss) attributable to common stockholders | $ | (968,031) |  |  | $ | 246,292 |  |  | $ | 154,658 |
Weighted average number of common shares outstanding, excluding non-vested restricted stock units | 397,196 |  |  | 279,501 |  |  | 215,935 |
Basic net income (loss) per common share | $ | (2.44) |  |  | $ | 0.88 |  |  | $ | 0.72 |
DILUTED EPS: |  |  |  |  |
Net income (loss) attributable to common stockholders | $ | (968,031) |  |  | $ | 246,292 |  |  | $ | 154,658 |
Weighted average number of common shares outstanding, excluding non-vested restricted stock units | 397,196 |  | 280,061 |  | 219,496
Diluted net income (loss) per common share | $ | (2.44) |  |  | $ | 0.88 |  |  | $ | 0.70 |
Potentially dilutive securities excluded as anti-dilutive | 7,674 |  | 9,214 |  | 3,541

16. Employee Benefits
We maintain a 401(k) plan for all eligible employees. Our operating results include expenses of approximately $34.6 million in 2024, $18.7 million in 2023 and $11.0 million in 2022 for our contributions to the plan.
17. Business Segments
Our Chief Operating Decision Maker (“CODM”) is our Chief Executive Officer, who has ultimate responsibility for enterprise decisions. Effective as of the third quarter of 2023, we revised our reportable segments to align with certain changes in how our
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CODM manages and allocates resources to our business as a result of the Ulterra acquisition and NexTier merger. Our business is organized based on the services and products we provided 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, which was acquired with our acquisition of Ulterra on August 14, 2023.
Our results for the year ended December 31, 2024 are not comparable for our Completion Services and Drilling Products reportable segments since results for 2023 include a partial period beginning on the closing date for each acquisition.
Geographic Information
Consolidated revenues by country based on sales destination of the products or services for the years ended December 31, 2024, 2023 and 2022 are as follows (in thousands):

| Year Ended December 31,
| 2024 |  | 2023 |  | 2022
Revenue: |  |  |  |  |
United States | $ | 5,249,154 |  |  | $ | 4,057,212 |  |  | $ | 2,577,471 |
Canada | 33,518 |  |  | 12,501 |  |  | — |
Colombia | 12,223 |  |  | 48,592 |  |  | 70,121 |
Other Countries | 83,016 |  |  | 28,151 |  |  | — |
Total revenues | $ | 5,377,911 |  |  | $ | 4,146,456 |  |  | $ | 2,647,592 |

Property and equipment, net by country based on the location for the years ended December 31, 2024, 2023 and 2022 are as follows (in thousands):

| Year Ended December 31,
| 2024 |  | 2023 |  |
Property and equipment, net: |  |  |  |  |
United States | $ | 2,950,342 |  |  | $ | 3,257,937 |  |  |
Canada | 12,695 |  |  | 16,018 |  |  |
Colombia | 35,154 |  |  | 48,302 |  |  |
Other Countries | 12,151 |  |  | 18,155 |  |  |
Property and equipment, net | $ | 3,010,342 |  |  | $ | 3,340,412 |  |  |

Major Customer — During 2024, one customer accounted for approximately $605 million or 11% of our consolidated operating revenues. These revenues were earned in the drilling services, completion services, and drilling products businesses. During 2023, one customer accounted for approximately $588 million or 14% of our consolidated operating revenues. These revenues were earned in both drilling services and completion services businesses. During 2022, one customer accounted for approximately $476 million or 18% of our consolidated operating revenues. These revenues were earned in both drilling services and completion services businesses.
The following tables summarize selected financial information relating to our business segments (in thousands):
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| Drilling Services |  | Completion Services |  | Drilling Products |  | Total
Year Ended December 31, 2024 |  |  |  |  |  |  |
Revenues from external customers | $ | 1,727,810 |  |  | $ | 3,232,785 |  |  | $ | 351,651 |  |  | $ | 5,312,246 |
Direct operating costs (1) | 1,029,591 |  |  | 2,658,170 |  |  | 191,107 |  |  | 3,878,868 |
Selling, general and administrative | 16,502 |  |  | 41,557 |  |  | 35,860 |  |  | 93,919 |
Depreciation, amortization and impairment (1) | 477,398 |  |  | 564,155 |  |  | 100,610 |  |  | 1,142,163 |
Impairment of goodwill | — |  |  | 885,240 |  |  | — |  |  | 885,240 |
Other segment items (2) | — |  |  | (17,792) |  |  | — |  |  | (17,792) |
Segment operating income (loss) (3) | $ | 204,319 |  |  | $ | (898,545) |  |  | $ | 24,074 |  |  | $ | (670,152) |
Reconciliation of revenue:
Total segment revenues from external customers |  |  |  |  |  |  | $ | 5,312,246 |
Other revenues (4) |  |  |  |  |  |  | 65,665 |
Total consolidated revenues |  |  |  |  |  |  | $ | 5,377,911 |
Reconciliation to consolidated income (loss) before income taxes:
Segment operating income (loss) (3) |  |  |  |  |  |  | $ | (670,152) |
Other (4) |  |  |  |  |  |  | (87) |
Corporate |  |  |  |  |  |  | (219,498) |
Interest income |  |  |  |  |  |  | 5,729 |
Interest expense |  |  |  |  |  |  | (71,963) |
Other income (expense) |  |  |  |  |  |  | (975) |
Income before income taxes |  |  |  |  |  |  | $ | (956,946) |
| Drilling Services |  | Completion Services |  | Drilling Products |  | Total
Year Ended December 31, 2023 |  |  |  |  |  |  |
Revenues from external customers | $ | 1,919,759 |  |  | $ | 2,017,440 |  |  | $ | 134,679 |  |  | $ | 4,071,878 |
Direct operating costs (1) | 1,119,200 |  |  | 1,567,940 |  |  | 81,555 |  |  | 2,768,695 |
Selling, general and administrative | 15,014 |  |  | 26,050 |  |  | 11,158 |  |  | 52,222 |
Depreciation, amortization and impairment (1) | 364,312 |  |  | 283,230 |  |  | 48,467 |  |  | 696,009 |
Other segment items (2) | (769) |  |  | — |  |  | — |  |  | (769) |
Segment operating income (loss) (3) | $ | 422,002 |  |  | $ | 140,220 |  |  | $ | (6,501) |  |  | $ | 555,721 |
Reconciliation of revenue:
Total segment revenues from external customers |  |  |  |  |  |  | $ | 4,071,878 |
Other revenues (4) |  |  |  |  |  |  | 74,578 |
Total consolidated revenues |  |  |  |  |  |  | $ | 4,146,456 |
Reconciliation to consolidated income (loss) before income taxes:
Segment operating income (3) |  |  |  |  |  |  | $ | 555,721 |
Other (4) |  |  |  |  |  |  | 2,829 |
Corporate |  |  |  |  |  |  | (206,596) |
Interest income |  |  |  |  |  |  | 6,122 |
Interest expense |  |  |  |  |  |  | (52,870) |
Other income (expense) |  |  |  |  |  |  | 1,898 |
Income before income taxes | $ | 307,104 |

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| Drilling Services |  | Completion Services |  | Drilling Products |  | Total
Year Ended December 31, 2022 |  |  |  |  |  |  |
Revenues from external customers | $ | 1,544,820 |  |  | $ | 1,022,413 |  |  | $ | — |  |  | $ | 2,567,233 |
Direct operating costs (1) | 1,025,904 |  |  | 781,385 |  |  | — |  |  | 1,807,289 |
Selling, general and administrative | 15,027 |  |  | 8,763 |  |  | — |  |  | 23,790 |
Depreciation, amortization and impairment (1) | 354,116 |  |  | 98,162 |  |  | — |  |  | 452,278 |
Other segment items (2) | (34) |  |  | — |  |  | — |  |  | (34) |
Segment operating income (3) | $ | 149,807 |  |  | $ | 134,103 |  |  | $ | — |  |  | $ | 283,910 |
Reconciliation of revenue: |  |  |  |  |  |  |
Total segment revenues from external customers |  |  |  |  |  |  | $ | 2,567,233 |
Other revenues (4) |  |  |  |  |  |  | 80,359 |
Total consolidated revenues |  |  |  |  |  |  | $ | 2,647,592 |
Reconciliation to consolidated income (loss) before income taxes:
Segment operating income (3) |  |  |  |  |  |  | $ | 283,910 |
Other (4) |  |  |  |  |  |  | 13,776 |
Corporate |  |  |  |  |  |  | (86,655) |
Interest income |  |  |  |  |  |  | 360 |
Interest expense |  |  |  |  |  |  | (40,256) |
Other income (expense) |  |  |  |  |  |  | (3,273) |
Income before income taxes | $ | 167,862 |

(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.
Other business segment information

| Year Ended December 31,
| 2024 |  | 2023 |  | 2022
Capital expenditures: |  |  |  |  |
Drilling Services | $ | 264,667 |  |  | $ | 334,780 |  |  | $ | 272,521 |
Completion Services | 320,329 |  |  | 214,746 |  |  | 137,935 |
Drilling Products | 61,687 |  |  | 24,572 |  |  | — |
Segment capital expenditures | $ | 646,683 |  |  | $ | 574,098 |  |  | $ | 410,456 |
Other | 21,813 |  |  | 24,645 |  |  | 25,215 |
Corporate | 9,890 |  |  | 16,947 |  |  | 1,126 |
Total capital expenditures | $ | 678,386 |  |  | $ | 615,690 |  |  | $ | 436,797 |
Identifiable assets: |  |  |  |  |
Drilling Services | $ | 2,047,986 |  |  | $ | 2,368,604 |  |  | $ | 2,348,177 |
Completion Services | 2,468,707 |  |  | 3,835,699 |  |  | 541,975 |
Drilling Products | 966,200 |  |  | 1,011,870 |  |  | — |
Segment assets | $ | 5,482,893 |  |  | $ | 7,216,173 |  |  | $ | 2,890,152 |
Other | 55,580 |  |  | 59,221 |  |  | 64,018 |
Corporate (1) | 294,993 |  |  | 144,637 |  |  | 189,653 |
Total assets | $ | 5,833,466 |  |  | $ | 7,420,031 |  |  | $ | 3,143,823 |

(1) Corporate assets primarily include cash on hand and certain property and equipment.
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18. 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 December 31, 2024 and 2023 is set forth below (in thousands):

| 2024 |  | 2023
| Carrying Value |  | Fair Value |  | Carrying Value |  | Fair Value
3.95% Senior Notes Due 2028 | $ | 482,505 |  |  | $ | 461,720 |  |  | $ | 482,505 |  |  | $ | 450,540 |
5.15% Senior Notes Due 2029 | 344,895 |  |  | 336,490 |  |  | 344,895 |  |  | 329,032 |
7.15% Senior Notes Due 2033 | 400,000 |  |  | 419,265 |  |  | 400,000 |  |  | 424,946 |
Equipment Loans Due 2025 | 6,395 |  |  | 6,424 |  |  | 18,686 |  |  | 18,766 |
Total debt | $ | 1,233,795 |  |  | $ | 1,223,899 |  |  | $ | 1,246,086 |  |  | $ | 1,223,284 |

The fair values of the 2028 Notes, the 2029 Notes and the 2033 Notes at December 31, 2024 and 2023 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 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 December 31, 2024 and 2023 are set forth below:

| 2024 |  | 2023
3.95% Senior Notes Due 2028 | 5.49 | % |  | 5.79 | %
5.15% Senior Notes Due 2029 | 5.73 | % |  | 6.10 | %
7.15% Senior Notes Due 2033 | 6.42 | % |  | 6.28 | %
Equipment Loans Due 2025 | 5.28 | % |  | 5.36 | %

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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

|  |  |  | Additions and adjustments |  |  |  |
Description |  | Beginning Balance |  | Charged to Costs and Expenses |  | Charged to Other Accounts |  | Deductions |  | Ending Balance
|  | (In thousands)
Year Ended December 31, 2024 |  |  |  |  |  |  |  |  |  |
Allowance for credit losses |  | $ | 3,490 |  |  | $ | 5,755 |  |  | $ | 6,050 |  |  | $ | (248) |  | (1) | $ | 15,047 |
Deferred tax valuation allowance |  | 75,250 |  |  | 11,443 |  |  | — |  |  | — |  |  | 86,693 |
Year Ended December 31, 2023 |  |  |  |  |  |  |  |  |  |
Allowance for credit losses |  | $ | 2,875 |  |  | $ | 842 |  |  | $ | 43 |  |  | $ | (270) |  | (1) | $ | 3,490 |
Deferred tax valuation allowance |  | 91,685 |  |  | — |  |  | 13,677 |  |  | (30,112) |  |  | 75,250 |
Year Ended December 31, 2022 |  |  |  |  |  |  |  |  |  |
Allowance for credit losses |  | $ | 8,493 |  |  | $ | — |  |  | $ | — |  |  | $ | (5,618) |  | (1) | $ | 2,875 |
Deferred tax valuation allowance |  | 189,737 |  |  | — |  |  | — |  |  | (98,052) |  |  | 91,685 |

_____________________________________
(1)Consists of uncollectible accounts written-off.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Patterson-UTI Energy, Inc. has duly caused this Report on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized.

| PATTERSON-UTI ENERGY, INC.
| By: | /s/ William Andrew Hendricks, Jr.
|  | William Andrew Hendricks, Jr.
|  | President and Chief Executive Officer

Date: February 11, 2025
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report on Form 10-K has been signed by the following persons on behalf of Patterson-UTI Energy, Inc. and in the capacities indicated as of February 11, 2025.

Signature |  | Title
/s/ Curtis W. Huff |  | Chairman of the Board
Curtis W. Huff |  |
/s/ Robert W. Drummond |  | Vice Chairman of the Board
Robert W. Drummond |  |
/s/ William Andrew Hendricks, Jr. |  | President, Chief Executive Officer
William Andrew Hendricks, Jr. |  | and Director
(Principal Executive Officer) |  |
/s/ C. Andrew Smith |  | Executive Vice President and
C. Andrew Smith |  | Chief Financial Officer
(Principal Financial and Accounting Officer) |  |
/s/ Leslie A. Beyer |  | Director
Leslie A. Beyer |  |
/s/ Tiffany Thom Cepak |  | Director
Tiffany Thom Cepak |  |
/s/ Gary M. Halverson |  | Director
Gary M. Halverson |  |
/s/ Cesar Jaime |  | Director
Cesar Jaime |  |
/s/ Janeen S. Judah |  | Director
Janeen S. Judah |  |
/s/ Amy H. Nelson |  | Director
Amy H. Nelson |  |
/s/ Julie J. Robertson |  | Director
Julie J. Robertson |  |
/s/ James C. Stewart |  | Director
James C. Stewart |  |

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