10-K

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ or No ☐

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 ☐ or No ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 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 ☒ or No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company”, and “emerging growth company” in Rule 12b-2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant 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. ☒

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. ☐

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). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2023, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $2.4 billion, calculated by reference to the closing price of $11.97 for the common stock on the Nasdaq Global Select Market on that date.

As of February 20, 2024, the registrant had outstanding 408,192,236 shares of common stock, $0.01 par value, its only class of common stock.

Portions of the registrant’s definitive proxy statement for the 2024 Annual Meeting of Stockholders are incorporated by reference into Part III of this report.

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,” “predict,” “potential,” “project,” “pursue,” “should,” “strategy,” “target,” or “will,” or the negative thereof and other words and expressions of similar meaning. The forward-looking statements are based on certain assumptions and analyses we make in light of our experience and our perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances.

Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. These forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from actual future results expressed or implied by the forward-looking statements. These risks and uncertainties 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:

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.

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.

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.

Our contract drilling business operates in the continental United States and internationally in Colombia and, from time to time, we pursue contract drilling opportunities in other select markets. 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.

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.

We serve the energy and mining markets by manufacturing and distributing drill bits through 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 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.

Recent Developments in Market Conditions — Quarterly average oil prices and our quarterly average number of rigs operating in the United States for 2021, 2022 and 2023 are as follows:

Our revenues, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas and expectations about future prices. Crude oil prices and demand for drilling and completion equipment and services increased from 2021 to 2022, and industry supply of Tier-1, super-spec rigs became constrained. Commodity price volatility in the second quarter of 2023 resulted in a decline in industry activity; commodity prices subsequently increased during the third quarter before declining in the fourth quarter of 2023. We expect our rig count in the United States will average 120 rigs in the first quarter. The current demand for equipment and services remains dependent on 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 $78.53 per barrel in the fourth quarter of 2023 and closed at $78.72 per barrel on February 20, 2024. Natural gas prices (based on the Henry Hub Spot Market Price) averaged $2.74 per MMBtu in the fourth quarter of 2023 and closed at $1.50 per MMBtu on February 20, 2024.

Our average active U.S. rig count for the fourth quarter of 2023 was 118 rigs. This was a decrease from our average active rig count for the third quarter of 2023 of 120 rigs. Our active U.S. rig count at December 31, 2023 of 121 rigs was less than the rig count of 132 rigs at December 31, 2022, due in large part to the decline in commodity prices and reduced demand for drilling services in the United States. We expect our rig count in the United States will average 120 rigs in the first quarter of 2024. Term contracts help support our operating rig count. Based on contracts in place in the United States as of February 14, 2024, we expect an average of 79 rigs operating under term contracts during the first quarter of 2024 and an average of 52 rigs operating under term contracts during 2024.

Our completion services business was impacted by calendar inefficiencies during the second half of 2023 resulting from a decline in customer activity during the third quarter. Completion services activity stabilized in the fourth quarter of 2023. We believe activity will modestly decline in the first quarter of 2024.

Drilling products demand increased from the third quarter of 2023 despite a decline in the global rig count. Drilling Products demand is expected to remain steady through the first quarter, given the expectation for a steady market in the U.S. and moderate growth in international markets relative to what we saw in the fourth quarter.

Recent Developments in Business Combinations and Financial Matters — On September 1, 2023, we completed the NexTier merger. 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 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. 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.

our common stock of $14.94 on August 14, 2023, valued the transaction at closing at approximately $897 million. Ulterra is a global provider of specialized drill bit solutions.

On September 13, 2023, we completed the offering of $400 million in aggregate principal amount of our 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 revolving credit facility.

On August 29, 2023, we entered into Amendment No. 4 to Amended and Restated Credit Agreement (the “Credit Agreement Amendment”), which amended our Amended and Restated Credit Agreement, dated as of March 27, 2018 (as amended, the “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 Credit Agreement Amendment, among other things, (i) deemed certain outstanding letters of credit issued for the account of BEP Diamond Holdings Corp. (the entity we acquired in the Ulterra acquisition) with a face amount of $2.5 million to have been issued under the Credit Agreement, and (ii) extended the maturity date for $85 million of revolving credit commitments of certain lenders under the Credit Agreement from March 27, 2025 to March 27, 2026. As a result, of the $600 million of revolving credit commitments under the Credit Agreement, the maturity date for $501.7 million of such commitments is March 27, 2026; the maturity date for $48.3 million of such commitments is March 27, 2025; and the maturity date for the remaining $50 million of such commitments is March 27, 2024.

During the first quarter of 2023, we elected to repurchase portions of our 3.95% Senior Notes due 2028 (the “2028 Notes”) and our 5.15% Senior Notes due 2029 (the “2029 Notes”) in the open market. The principal amounts retired through these transactions totaled $6.0 million of our 2028 Notes and $3.0 million of our 2029 Notes, plus accrued interest. We recorded corresponding gains on the extinguishment of these amounts totaling $0.8 million and $0.3 million, respectively, net of the proportional write-off of associated deferred financing costs and original issuance discounts. These gains are included in “Interest expense, net of amount capitalized” in our consolidated statements of operations included as a part of Item 8 of this Report.

As of December 31, 2023, we had no borrowings outstanding under our revolving credit facility. We had $2.6 million in letters of credit outstanding under the Credit Agreement at December 31, 2023 and, as a result, had available borrowing capacity of approximately $597 million at that date.

Our revenues, operating income and loss and identifiable assets are primarily attributable to three industry segments:

General — We provide our contract drilling services to oil and natural gas operators in the United States and Colombia. As of December 31, 2023, we had 192 marketed land-based drilling rigs based in the following regions:

All of these drilling rigs are electric rigs. An electric rig converts the power from its diesel 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 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, 2023, we had 173 super-spec rigs, of which 131 were 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 spend 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 many having high pressure mud systems, walking systems and increased hookload capacity. During fiscal years 2023, 2022 and 2021, we spent approximately $335 million, $256 million, and $110 million, respectively, on these capital expenditures.

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, drill bits, 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:

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. We had no impairment related to the marketability or condition of our drilling rigs during 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, in most major onshore oil and natural gas basins in the United States. We generally design, assemble and maintain our own fleet of downhole drilling motors and MWD equipment. 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.

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.

Completion Support Services — In late 2020, NexTier began evolving its completion service offerings to develop an integrated natural gas treatment and delivery solution. In 2021, NexTier launched its Power Solutions business, which focuses on gas sourcing, compression, transport, decompression, treatment and related services for fracturing operations. We believe this integration solution assists our customers by reducing emissions at the wellsite and throughout their operations. As part of NexTier’s wellsite integration strategy to provide and integrate a variety of services for its customers at the wellsite to maximize efficiencies and profitability, in 2022, NexTier acquired sand hauling, wellsite storage, and last mile logistics assets and rebranded its entire last mile logistics operation as NexMile Logistics. The assets acquired were combined with NexTier’s 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 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. We had no impairment related to the marketability or condition of our equipment during 2023.

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 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.

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 or condition of our equipment during 2023.

Our oilfield rentals business has a fleet of premium rental tools 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.

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.

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.

Our customer base includes major, independent and other oil and natural gas operators. With respect to our consolidated operating revenues in 2023, we received approximately 49% from our ten largest customers and approximately 35% from our five largest customers. During 2023, one customer accounted for approximately $588 million, or approximately 14%, 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.

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, 2023 and 2022 was approximately $700 million and $830 million, respectively. Approximately 16% of our contract drilling backlog in the United States at December 31, 2023 is reasonably expected to remain after 2024. 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.

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.

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.

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.

Employees – We had approximately 10,600 full-time employees as of January 31, 2024. 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.

We require new supervisors and managers in the United States to attend an instructor-led course relative to diversity, inclusion and respect to ensure they understand our expectations regarding their obligations to promote a work environment where all employees are valued and respected. Supplemental diversity, inclusion and respect training for supervisors and managers is required on a biannual basis. All other 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.

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:

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.

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, employer’s liability, automobile liability, commercial general liability, workers’ compensation as well as insurance for other specific risks. 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. We have also elected in some

cases to retain a greater amount of risk through increased deductibles on certain insurance policies. For example, in the United States we generally maintain a $1.5 million per occurrence deductible on our workers’ compensation insurance coverage, a $1.0 million per occurrence deductible on our equipment insurance coverage, a $10.0 million per occurrence deductible on our general liability coverage, and, for our automobile insurance coverage, a per occurrence deductible ranging from $2.0 million to $10.0 million. 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, 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 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. Occasionally, our operations have been negatively impacted by severe weather conditions.

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.

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.

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:

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:

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:

All of these factors are beyond our control. Crude oil prices and demand for drilling and completion equipment and services increased in 2022, and industry supply of Tier-1, super-spec rigs became constrained. Commodity price volatility in the second quarter of 2023 resulted in a decline in industry activity; commodity prices subsequently increased during the third quarter before declining in the fourth quarter of 2023. The current demand for equipment and services remains dependent on 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 $78.53 per barrel in the fourth quarter of 2023 and closed at $78.72 per barrel on February 20, 2024. Natural gas prices (based on the Henry Hub Spot Market Price) averaged $2.74 per MMBtu in the fourth quarter of 2023 and closed at $1.50 per MMBtu on February 20, 2024.

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

Concerns regarding global economic conditions, energy costs, geopolitical issues, supply chain disruptions, inflation and the availability and cost of credit have contributed 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 Israel and Hamas, 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 and changes in production from OPEC, its members and other oil-producing nations. 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 at times available drilling services equipment, completion services equipment, and drilling products exceed the demand for such equipment and products. A low commodity price environment or capital spending reductions by our customers due to customer consolidation (which is currently occurring in the industry), 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 both our customers and competitors, 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 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 $7.0 million, $4.5 million and $267 million in 2023, 2022 and 2021, 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. 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 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 which we are not fully insured or indemnified could materially adversely affect 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, 2023, 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 $700 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 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.

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 of large customers could have a material adverse effect on our financial condition and results of operations.

With respect to our consolidated operating revenues in 2023, we received approximately 49% from our ten largest customers, approximately 35% from our five largest customers and 14% from our largest customer. 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.

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:

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.

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:

Some of our office personnel remain 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, such as the ongoing armed conflicts between Russia and Ukraine and Israel and Hamas and the continuation of, or any escalation in the severity of, these conflicts, may heighten the risk of cybersecurity attacks and other cyber events.

Although we utilize various procedures and controls to mitigate our exposure to the risks described above, cybersecurity attacks and other cyber events are evolving and unpredictable. 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. 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.

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.

In addition, because we, NexTier and Ulterra previously operated independently, it is possible that the integration process could result in:

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 for liabilities arising from events occurring before such acquisitions, we may be unable to do so, and any indemnities we do obtain will be limited in amount and duration, 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.

Our business relationships may be subject to disruption due to uncertainty associated with any pending or recently completed acquisitions, including the NexTier merger or the Ulterra acquisition, which could have a material adverse effect on our results of operations, cash flows and financial position.

Parties with which we do business may experience uncertainty associated with any pending or recently completed acquisitions, such as the NexTier merger and the Ulterra acquisition, including with respect to current or future business relationships with us. Our business relationships may be subject to disruption as customers, distributors, suppliers, vendors, landlords, joint venture partners and other business partners may attempt to delay or defer entering into new business relationships, negotiate changes in existing business relationships or consider entering into business relationships with parties other than us. These disruptions could have a material adverse effect on our results of operations, cash flows and financial position, as well as a material adverse effect on our ability to realize the expected cost savings and other benefits of the applicable transaction.

Public health crises, pandemics and epidemics may have a significant adverse impact on our business, liquidity, results of operations and financial condition.

The effects of public health crises, pandemics and epidemics, including related governmental actions and restrictions related thereto, have had, and may in the future have, a significant adverse impact on the global economy, including the worldwide demand for oil and natural gas, and the level of demand for our services.

We are not able to enumerate all potential risks to our business from the emergence of a public health crisis, pandemic or epidemic; however, we believe that in addition to the impacts described above, other current and potential impacts include, but are not limited to: volatility in oil and natural gas prices; liquidity challenges; customers, suppliers and other third parties seeking to terminate, reject, renegotiate or otherwise avoid, and otherwise failing to perform, their contractual obligations to us; credit rating downgrades of our corporate debt and potentially higher borrowing costs in the future; a need to preserve liquidity; cybersecurity issues; litigation risk and possible loss contingencies; disruption to our supply chain; loss of workers and labor shortages; general oilfield cost inflation; a reduction of our workforce; costs associated with rationalization of our portfolio of real estate facilities; asset impairments and other accounting charges; infections and quarantining of our employees and the personnel of our customers, suppliers and other third parties; actions undertaken by international, national, regional and local governments and health officials; and a structural shift in the global economy and its demand for oil and natural gas.

The full extent of the impact of public health crises, pandemics and epidemics on the oil and natural gas industry and our business, liquidity, results of operations and financial condition will depend largely on the scale of such event, including the duration and spread of a subject pathogen, the impact of governmental actions designed to prevent the spread thereof and the further development, availability, timely distribution and acceptance of effective treatments and vaccines.

Fuel conservation measures 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.

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, 2023, we had approximately $1.9 billion of gross U.S. federal net operating losses, approximately $62.3 million of gross Canadian net operating losses, approximately $22.6 million of gross Colombian net operating losses and approximately $1.1 billion of post-apportionment U.S. state net operating losses as of December 31, 2023, before valuation allowances. The majority of U.S. federal net operating losses will expire in varying amounts, if unused, between 2030 and 2037. U.S. federal net operating losses generated after 2017 can be carried forward indefinitely. Canadian net operating losses will expire in varying amounts, if unused, between 2036 and 2043. Colombian net operating losses will expire in varying amounts, if unused, between 2028 and 2032. U.S. state net operating losses will expire in varying amounts, if unused, between 2024 and 2043.

Section 382 of the 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.

Uncertainties associated with the NexTier merger and the Ulterra acquisition may cause a loss of management personnel and other key employees, which could adversely affect our future business and operations.

We are dependent on the experience and industry knowledge of our officers and other key employees to execute our business plans. Our success will depend in part upon our ability to retain key management personnel and other key employees. Current and prospective employees may experience uncertainty about their roles within the combined company or other concerns regarding the operations of the combined company following the transactions, any of which may have an adverse effect on our ability to retain or attract key management and other key personnel. In addition, the loss of key personnel could diminish the anticipated benefits of the transactions and the integration of the companies may be more difficult. Furthermore, we may have to incur significant costs in identifying, hiring and retaining replacements for departing employees and may lose significant expertise and talent relating to the business of each of the companies. No assurance can be given that we will be able to retain or attract key management personnel and other key employees to the same extent that we have previously been able to retain or attract our own employees.

We have incurred and are expected to continue incurring transaction costs in connection with the NexTier merger and the Ulterra acquisition, which may be in excess of those we anticipated.

We have incurred and are expected to continue to incur non-recurring costs associated with completing the NexTier merger and the Ulterra acquisition, combining the operations of the three companies and achieving desired synergies. These costs have been, and may continue to be, substantial. We have incurred and will continue to incur costs related to formulating and implementing integration plans, including facilities and systems consolidation costs and other employment-related costs. We will continue to assess the magnitude of these costs, and additional unanticipated costs may be incurred in connection with the integration of the companies’ businesses. While we have assumed that a certain level of expenses would be incurred, there are many factors beyond our control that could affect the total amount or the timing of the expenses. The elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the businesses, may not offset integration-related costs to the extent anticipated. The costs described above and any unanticipated costs and expenses could have an adverse effect on our financial condition and operating results.

The benefits and synergies attributable to the NexTier merger and the Ulterra acquisition may vary from expectations.

We may fail to realize the anticipated benefits and synergies expected from the NexTier merger and the Ulterra acquisition, which could adversely affect our business, financial condition and operating results. The success of the transactions will depend, in significant part, on our ability to successfully integrate the acquired businesses and realize the anticipated strategic benefits and synergies from the transactions. The anticipated benefits of the transactions may not be realized fully or at all, or may take longer to realize than expected. Actual operating, technological, strategic and revenue opportunities, if achieved at all, may be less significant than expected or may take longer to achieve than anticipated. If we are not able to achieve these objectives and realize the anticipated benefits and synergies expected from the NexTier merger and the Ulterra acquisition within the anticipated timing or at all, our business, financial condition and operating results may be adversely affected.

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, the federal Bureau of Land Management (“BLM”) published a final rule in 2015 establishing new or more stringent standards for performing hydraulic fracturing on federal and Indian lands. The BLM rescinded the 2015 rule in late 2017; however, new or more stringent regulations may be promulgated by the Biden administration. The United States may seek to adopt federal regulations or enact federal laws that would impose additional regulatory requirements on or even prohibit hydraulic fracturing in some areas. 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) that could affect our operations. Four states (New York, Maryland, Vermont, and Washington) have banned the use of high volume hydraulic fracturing, Oregon has adopted a five-year moratorium, 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 the absence of federal GHG-limiting legislation, 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, 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.

The United States is currently a member of the Paris Agreement, which requires countries to review and “represent a progression” in their nationally determined contributions, which set emissions reduction goals, every five years. Under the Paris Agreement, the Biden Administration has committed the United States to reducing its greenhouse gas emissions by 50-52% from 2005 levels by 2030. 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 the goals of the Paris Agreement.

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. President Biden and the Democratic Party have identified climate change as a priority, and it is possible that additional executive orders and/or regulatory action targeting greenhouse gas emissions, or prohibiting or restricting oil and natural gas development activities in certain areas, will be proposed and/or promulgated during the Biden Administration. In 2021, President Biden issued an executive order imposing a moratorium on new oil and natural gas leasing on federal lands and offshore waters pending completion of a comprehensive review and reconsideration of federal oil and natural gas permitting and leasing practices. President Biden’s order also established climate change as a primary foreign policy and national security consideration, affirms that achieving net-zero greenhouse gas emissions by or before midcentury is a critical priority, affirms the Biden Administration’s desire to establish the United States as a leader in addressing climate change, generally further integrates climate change and environmental justice considerations into government agencies’ decision-making, and eliminates fossil fuel subsidies, among other measures. Although a federal judge for the U.S. District Court of the Western District of Louisiana issued a permanent injunction in 13 states that filed a lawsuit against the pause of oil and natural gas leasing on public lands or in offshore waters, the Biden Administration may take other regulatory steps in the future that could impact our operations. Other actions impacting oil and natural gas production activities that could be pursued by the Biden administration may include more restrictive requirements for the establishment of pipeline infrastructure or the permitting of liquified natural gas export facilities, such as the January 2024 pause on permitting of certain new liquified natural gas export facilities. Moreover, in August 2022, President Biden signed into law the Inflation Reduction Act, which contains tax inducements and other provisions that incentivize investment, development, and deployment of alternative energy sources and technologies, which could increase operating costs within the oil and natural gas industry and accelerate the transition away from fossil fuels.

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.

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.

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 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.

Technology 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 adverse effect on our business, financial condition and results of operations.

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 should such equipment fail to perform to specifications.

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. 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. We also continue to evaluate opportunities from time to time to provide our services and products 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) 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.

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 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.

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. Our ESG practices and disclosures may not satisfy investor requirements 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, and reporting such metrics, including any climate change and sustainability-related public company disclosure requirements adopted by the SEC, and such standards may change over time, which could result in significant revisions to our current ESG practices and disclosures.

The lending and investment practices of institutional lenders and investors have been the subject of intensive lobbying efforts in recent years, oftentimes public in nature, not to provide funding for oil and natural gas producers, and some lenders and insurers have announced that they will not lend to or provide insurance for oil and natural gas companies. Limitation of investments in and financings for oil and natural gas could result in the restriction, delay, or cancellation of drilling and completion programs or development of production activities. An increasing number of our customers consider sustainability factors in awarding work. If we are unable to meet the ESG standards or investment criteria set by our customers, investors and other parties, which continue to evolve, if we are unable to successfully continue our sustainability enhancement efforts, or if, notwithstanding our own efforts, our industry becomes the focus of increasing ESG and sustainability related pressures, we may lose customers, we may lose investors, our cost of capital may increase, our stock price may be negatively impacted, our reputation may be negatively affected, and it may be more difficult for us to effectively compete or assess acquisitions. 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. By publishing our Sustainability Report from time to time, our business may also face increased scrutiny related to ESG activities and be unable to satisfy all stakeholders.

Variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

We have in place a committed senior unsecured credit facility that includes a revolving credit facility. 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 (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, 2023, 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, 2023, we had no borrowings outstanding under our revolving credit facility.

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 LIBOR rate plus 2.25% per annum. As of December 31, 2023, no amounts had been disbursed under any letters of credit, and we had $87.7 million in letters of credit outstanding under the reimbursement agreement.

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.

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:

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.

We have implemented and maintain a cybersecurity program that is aligned with the NIST Framework and reasonably 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.

Our Board has delegated the primary responsibility to oversee cybersecurity matters to the Audit Committee. The Audit Committee regularly 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 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. Such members of our senior leadership also report to the Board at least annually on cybersecurity matters, including information security and cybersecurity risk. We have protocols by which certain cybersecurity incidents that meet established reporting thresholds are escalated within the Company and, where appropriate, reported promptly to the Board 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 on information security and cybersecurity risk at least annually.

At the management level, our Vice President of Information Technology, who has extensive cybersecurity knowledge and skills gained from over 18 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 the Chief Financial Officer.

The 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 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 responding to security incidents. The IRP sets out a coordinated approach to investigating, containing, documenting, and mitigating incidents, including reporting findings and keeping senior management, the Board and other key stakeholders informed and involved as appropriate.

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 receive 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.”

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. 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 through North America and internationally in over 30 countries.

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.

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 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

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.

As of February 9, 2024, there were approximately 800 holders of record of our common stock.

On February 14, 2024, 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 15, 2024 to holders of record as of March 1, 2024. The amount and timing of all future dividend payments, if any, are subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of our debt agreements and other factors. Our Board of Directors may, without advance notice, reduce or suspend our dividend in order to improve our financial flexibility and position our company for long-term success. There can be no assurance that we will pay a dividend in the future.

The table below sets forth the information with respect to purchases of our common stock made by us during the quarter ended December 31, 2023.

The following graph compares the cumulative stockholder return of our common stock for the period from December 31, 2018 through December 31, 2023, with the cumulative total return of the S&P 500 Index, the S&P SmallCap 600 Index and the Oilfield Service Index.

The graph assumes investment of $100 on December 31, 2018 and reinvestment of all dividends.

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 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.

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, 2023, our rig fleet included 173 super-spec rigs, of which 131 were Tier-1, super-spec rigs.

To address evolving customer preferences for emissions-reducing equipment, we have invested in natural gas-powered equipment, including electric pumps, to replace legacy diesel completion services equipment.

Recent Developments in Market Conditions and Outlook — Crude oil prices and demand for drilling and completion equipment and services increased from 2021 to 2022, and industry supply of Tier-1, super-spec rigs became constrained. Commodity price volatility in the second quarter of 2023 resulted in a decline in industry activity; commodity prices subsequently increased during the third quarter before declining in the fourth quarter of 2023. The current demand for equipment and services remains dependent on 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 $78.53 per barrel in the fourth quarter of 2023 and closed at 78.72 per barrel on February 20, 2024. Natural gas prices (based on the Henry Hub Spot Market Price) averaged $2.74 per MMBtu in the fourth quarter of 2023 and closed at $1.50 per MMBtu on February 20, 2024.

Quarterly average oil prices and our quarterly average number of rigs operating in the United States for 2021, 2022 and 2023 are as follows:

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, 2023 and 2022 was approximately $700 million and $830 million, respectively. Approximately 16% of our total contract drilling backlog in the United States at December 31, 2023 is reasonably expected to remain after 2024. 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.”

Cash capital expenditures for 2023 totaled $616 million. This was an increase from the $437 million of cash capital expenditures in 2022 due largely to the Ulterra acquisition and NexTier merger in 2023. Based on our current outlook for activity, we expect our capital expenditures for 2024 to be approximately $740 million.

Recent Developments in Business Combinations — 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 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. 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.

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 $376 million cash, which based on the closing price of our common stock of $14.94 on August 14, 2023, valued the transaction at closing at approximately $897 million. Ulterra is a global provider of specialized drill bit solutions.

Recent Developments in Debt Financing — On September 13, 2023, we completed the offering of $400 million in aggregate principal amount of our 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 revolving credit facility.

During the fourth quarter of 2022, we elected to repurchase portions of our 2028 Notes and 2029 Notes (as defined above) in the open market. The principal amounts retired through these transactions totaled $21.0 million of our 2028 Notes and $1.4 million of our 2029 Notes, plus accrued interest. We recorded corresponding gains on the extinguishment of these amounts totaling $2.3 million and $0.1 million, respectively, net of the proportional write-off of associated deferred financing costs and original issuance discounts. These gains are included in “Interest expense, net of amount capitalized” in our consolidated statements of operations included as a part of Item 8 of this Report.

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, 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.

For the three years ended December 31, 2023, our operating revenues and net income consisted of the following (dollars in thousands):

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. Accordingly, we recast our results of operations for the first half of 2023 and the year ended December 31, 2022 to align with our revised reportable segments.

The following tables summarize results of operations by business segment for the years ended December 31, 2023 and 2022:

Revenues increased primarily due to improved pricing from our contract drilling business within the United States.

Direct operating costs increased primarily due to inflationary pressure on labor and supplies.

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

The changes for the year ended December 31, 2023 as compared to December 31, 2022 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. In order to provide a more meaningful basis for comparison, the discussion on changes below is focused on changes between comparable periods, excluding the effects of the NexTier merger. However, these comparisons do not necessarily reflect what the results of our legacy pressure pumping business would have been had the NexTier merger not occurred and our legacy pressure pumping business continued to operate as a standalone business.

Completion services revenues and direct operating costs, excluding the effects of the NexTier merger, decreased $80.5 million and $49.3 million, or 7.9% and 6.3%, respectively due to calendar inefficiencies and lower customer pricing in 2023.

Selling, general and administrative expense, excluding the effects of the NexTier merger, was relatively flat, totaling $9.5 million in 2023 compared to $8.8 million in 2022.

Depreciation, amortization and impairment, excluding the effects of the NexTier merger, increased $44.2 million, or 45%. The increase was primarily attributable to the change in the estimated useful lives of certain components to reflect recent trends in increased intensity and pumping hours per day in servicing larger jobs. See Note 1 of Notes to consolidated financial statements for additional information on this change in accounting estimate.

Capital expenditures, excluding the effects of the NexTier merger, decreased $32.8 million or 23.8%. The decrease was primarily due to the activation of our twelfth spread in 2022.

The results of our drilling products segment reflect the operations of our Ulterra acquisition, from the closing date of August 14, 2023 until December 31, 2023. As such, there were no comparable results for the year ended December 31, 2022.

Direct operating costs and depreciation, amortization and impairment were approximately $11.0 million and $18.0 million higher than they would have otherwise been, respectively, as a result of the step up to fair value of our drill bits in accordance with purchase accounting for a business combination.

Revenue decreased from 2022 primarily due to a $10.5 million decrease in our oil and natural gas revenues resulting from unfavorable crude oil market prices and decreased production. Average WTI-Cushing prices in 2023 were $77.58 per barrel as compared to $94.90 per barrel in 2022. This decrease was partially offset by a $4.7 million increase in revenues from our oilfield rentals business.

Selling, general and administrative expense increased primarily due to increased personnel costs as a result of higher headcount, wage growth and changes in stock-based compensation. A portion of the increased personnel costs resulted from incremental headcount for corporate functions as part of the NexTier merger.

Merger and integration expense increased due to closing the Ulterra acquisition and NexTier merger in 2023. The increase was primarily attributable to $84.8 million of accelerated stock-based compensation expense and additional cash compensation associated with severance payments as well as certain legal, financial advisory, and other professional fees in order to consummate the transactions.

Other operating income, net increased 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.

Interest income increased due to interest received from a higher average cash balance in 2023.

Interest expense increased due to the issuance of 2033 Notes in the third quarter of 2023 and finance leases acquired as part of the Ulterra acquisition and NexTier merger.

The increase in capital expenditures was primarily due to the purchase of an aircraft in 2023.

Effective as of the third quarter of 2023, we revised our reportable segments to align with certain changes in how our 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. Accordingly, we recast our results of operations for the years ended December 31, 2022 and 2021 to align with our revised reportable segments.

The following tables summarize our recast results of operations by business segment for the years ended December 31, 2022 and 2021:

Revenues increased primarily due to an increase in operating days and improved pricing within our contact drilling business as well as increased job activity and improved pricing within our directional drilling business. Average revenue per operating day increased primarily due to improved pricing.

Direct operating costs increased due to an increase in operating days, increased reactivation costs and inflationary cost pressure on labor and supplies within our contract drilling business. A portion of the increase in direct operating costs related to increased job activity and cost inflation within our directional drilling business.

Depreciation, amortization and impairment expense decreased primarily due to a $220 million impairment charge related to the abandonment of 43 legacy non-super-spec rigs and contract drilling equipment and the abandonment of an $11.4 million developed technology intangible asset and $2.5 million of directional drilling equipment in 2021. Additionally, depreciation, amortization and impairment expense decreased partially due to a lower depreciable asset base during 2022 as a result of the impairment charge taken in 2021.

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

Revenues increased primarily due to an increase in the number of higher revenue fracturing jobs, improved pricing and continued improvement in asset utilization and efficiency.

Direct operating costs increased primarily due to an increase in the number of higher cost fracturing jobs as well as inflationary cost pressure on labor and supplies.

Depreciation, amortization and impairment expense decreased due to a lower depreciable asset base in 2022 partially as a result of a $32.2 million impairment charge taken in 2021. This impairment charge was related to the abandonment of approximately 0.2 million horsepower within our fleet. Additionally, a portion of the decrease related to certain equipment that reached the end of its useful life during 2022. This decrease in 2022 outpaced incremental depreciation resulting from equipment additions in 2020 and 2021, when our capital expenditures were significantly lower.

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

Our drilling products segment was added through our acquisition of Ulterra in 2023. As such, there were no results for the years ended December 31, 2022 and 2021.

Revenue increased from 2021 primarily due to a $17.7 million increase in our oilfield rentals business revenues due to higher service volumes and improved pricing as well as a $13.5 million increase in our oil and natural gas revenues resulting from favorable crude oil market prices and increased production. Average WTI-Cushing prices in 2022 were $94.90 per barrel as compared to $68.14 per barrel in 2021.

Direct operating costs increased due to incremental production costs from our oil and natural gas assets as well as a higher service volume provided by our oilfield rentals business and cost inflation.

Depreciation, depletion, amortization and impairment increased primarily due to a $4.5 million impairment in our oil and natural gas assets in 2022.

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

Selling, general and administrative expense increased primarily due to increased personnel costs as a result of higher headcount, wage growth and changes in stock-based compensation.

Merger and integration expenses were recognized in 2021 related to the Pioneer acquisition, which closed on October 1, 2021, and the subsequent divestiture of Pioneer’s well servicing rig business and wireline business, which closed on December 31, 2021.

Other operating (income) expenses, net includes net gains associated with the disposal of assets. Accordingly, the related gains or losses have been excluded from the results of specific segments. The $12.5 million other operating income in 2022 was primarily due to the release of an $11.5 million cumulative translation adjustment from accumulated other comprehensive income into net income (loss) in our consolidated statements of operations upon substantially completing our exit from our Canadian operations.

Interest expense was favorably impacted by a gain on debt extinguishment of $2.5 million associated with the repurchase of portions of our 2028 Notes and 2029 Notes in 2022. Excluding the effects of the gain, interest expense would have increased by $0.7 million, a 1.8% increase. Additionally, on December 30, 2021, we repaid the final $50 million of borrowings under the 2019 Term Loan Agreement, and as a result had no remaining borrowings under the Term Loan Agreement as of December 31, 2021. Accordingly, we did not incur interest expense related to the Term Loan Agreement in 2022.

The $3.0 million change in other expense was primarily due to foreign currency adjustments related to our Colombian operations.

The effective tax rate increased by approximately 12.0% to 19.9% for 2023 compared to 7.9% for 2022. 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 ability to recognize a portion of our U.S. federal and state net operating losses resulted in a significant impact, through changes in valuation allowances, in our effective tax rate for the year ended December 31, 2023. This benefit was partly offset by state and local income taxes and various other permanent adjustments.

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.

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, 2023, we had approximately $435 million in working capital, including $193 million of cash and cash equivalents, and approximately $597 million available under our revolving credit facility.

As part of the NexTier merger, we assumed the obligations of NexTier Completions Solutions Inc. (“NCS”) under a Master Loan and Security Agreement (as amended, the “Master Agreement”) with Caterpillar Financial Services Corporation. The Master Agreement allows NCS to enter into secured equipment financing term loans from time to time (the “Equipment Loans”). The Equipment Loans may be drawn in multiple tranches, with each loan evidenced by a separate promissory note. The Master Agreement and the Equipment Loans contain customary affirmative and negative covenants, including limitations on further encumbrance of the collateral other than the applicable loans under the Master Agreement. We were in compliance with these covenants at December 31, 2023. The Equipment

Loans bear interest at a rate of 5.25% per annum, and we pay interest on the 1st of each month. The Equipment Loans will mature on June 1, 2025.

On August 29, 2023, we entered into the Credit Agreement Amendment, which amended our Credit Agreement. The Credit Agreement Amendment, among other things, (i) deemed certain outstanding letters of credit issued for the account of BEP Diamond Holdings Corp. (the entity we acquired in the Ulterra acquisition) with a face amount of $2.5 million to have been issued under the Credit Agreement and (ii) extended the maturity date for $85 million of revolving credit commitments of certain lenders under the Credit Agreement from March 27, 2025 to March 27, 2026. As a result, of the $600 million of revolving credit commitments under the Credit Agreement, the maturity date for $501.7 million of such commitments is March 27, 2026; the maturity date for $48.3 million of such commitments is March 27, 2025; and the maturity date for the remaining $50 million of such commitments is March 27, 2024.

The Credit Agreement is a committed senior unsecured revolving credit facility that permits aggregate borrowings of up to $600 million, including a letter of credit facility that, at any time outstanding, is limited to $100 million and a swing line 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 $300 million, not to exceed total commitments of $900 million.

Loans under the 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, 2023, 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 Credit Agreement. However, if any subsidiary guarantees or incurs debt, which does not qualify for certain limited exceptions and is otherwise, in the aggregate with all other similar debt, in excess of Priority Debt (as defined in the Credit Agreement), such subsidiary is required to become a guarantor under the Credit Agreement.

The Credit Agreement contains representations, warranties, affirmative and negative covenants and events of default and associated remedies that we believe are customary for agreements of this nature, including certain restrictions on our ability and the ability of each of our subsidiaries to grant liens and on the ability of each of our non-guarantor subsidiaries to incur debt. If our credit rating is below investment grade at both Moody’s and S&P, we will become subject to a restricted payment covenant, which would generally require us to have a Pro Forma Debt Service Coverage Ratio (as defined in the Credit Agreement) greater than or equal to 1.50 to 1.00 immediately before and immediately after making any restricted payment. Restricted payments include, among other things, dividend payments, repurchases of our common stock, distributions to holders of our common stock or any other payment or other distribution to third parties on account of our or our subsidiaries’ equity interests. Our credit rating is currently investment grade at both credit rating agencies. The Credit Agreement also requires that our total debt to capitalization ratio, expressed as a percentage, not exceed 50% as of the last day of each fiscal quarter. The Credit Agreement generally defines the total debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the end of the most recently ended fiscal quarter. We were in compliance with these covenants at December 31, 2023.

On March 16, 2015, we entered into a Reimbursement Agreement (the “Reimbursement Agreement”) with The Bank of Nova Scotia (“Scotiabank”), pursuant to which we may from time to time request that Scotiabank issue an unspecified amount of letters of credit. As of December 31, 2023, we had $87.7 million in letters of credit outstanding under the Reimbursement Agreement.

Under the terms of the Reimbursement Agreement, we will reimburse Scotiabank on demand for any amounts that Scotiabank has disbursed under any 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 LIBOR rate plus 2.25% per annum, calculated daily and payable monthly, in arrears, on the basis of a calendar year for the actual number of days elapsed, with interest on overdue interest at the same rate as on the reimbursement amounts. 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 $92.4 million of outstanding letters of credit at December 31, 2023, which was comprised of $87.7 million outstanding under the Reimbursement Agreement, $2.5 million outstanding under the Credit Agreement, and $2.2 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.

Our outstanding long-term debt at December 31, 2023 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 $18.7 million of our Equipment Loans. We were in compliance with all covenants under the associated agreements and indentures at December 31, 2023.

For a full description of the Credit Agreement, the Reimbursement Agreement, the 2028 Notes, the 2029 Notes, the 2033 Notes and the Equipment Loans, see Note 9 of Notes to consolidated financial statements included as a part of Item 8 of this Report.

On August 29, 2023, we entered into a Term Loan Agreement with Wells Fargo Bank, National Association, as administrative agent and a lender, and the other lenders party thereto (the “Term Loan Agreement”). The Term Loan Agreement was a committed senior unsecured term loan facility (the “Term Loan Facility”) that permitted a single borrowing of up to $300 million, which could be drawn by us on or before November 27, 2023. We terminated the Term Loan Facility on September 13, 2023 and, as a result, the commitments under the Term Loan Agreement also terminated in full. We did not borrow under the Term Loan Facility.

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 2024 to be approximately $740 million. The majority of these expenditures are expected to be used for normal, recurring items necessary to support our business.

We anticipate $96.4 million of expenditures in 2024 related to various contractual obligations such as certain commitments to purchase proppants and lease liabilities.

As of December 31, 2023, we had working capital of $435 million, including cash and cash equivalents of $193 million, compared to working capital of $278 million, including cash and cash equivalents of $138 million, at December 31, 2022.

During 2023, our uses of cash flow and borrowings under our revolving credit facility included:

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 April 2023, our Board of Directors approved an increase of the authorization under the stock buyback program to allow for an aggregate of $300 million 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, 2023, we had remaining authorization to purchase approximately $206 million of our outstanding common stock under the 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 billion of future share repurchases. Shares of stock purchased under the buyback program are held as treasury shares.

We acquired shares of stock from employees during 2023, 2022 and 2021 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”) and 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. Upon the issuance of shares for the Pioneer acquisition in October 2021, we withheld shares with respect to Pioneer employees’ tax withholding obligations.

Treasury stock acquisitions during the years ended December 31, 2023, 2022 and 2021 were as follows (dollars in thousands):

As of December 31, 2023, we had unrecognized compensation costs of $51.4 million and $11.1 million related to our unvested restricted stock units and our unvested Performance Units, respectively. The weighted-average remaining vesting periods for these awards were 1.63 years and 1.13 years, respectively as of December 31, 2023. 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, 2023, we had commitments to purchase major equipment totaling approximately $153 million.

Our completion services segment has entered into agreements to purchase minimum quantities of proppants from certain vendors. As of December 31, 2023, the remaining minimum obligation under these agreements was approximately $39.7 million, of which approximately $33.7 million, $4.0 million and $2.0 million relate to the remainder of 2024, 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, 2023.

As part of the Ulterra acquisition and NexTier merger, we acquired additional operating and finance leases. Operating lease liabilities totaled $51.4 million and finance lease liabilities totaled $56.9 million at December 31, 2023. See Note 13 of Notes to consolidated financial statements in Item 8 of this Report for additional information on our operating leases as of December 31, 2023.

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.

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 45% of our total assets as of December 31, 2023 and depreciation, depletion, amortization and impairment represented 19% of our total operating costs and expenses in 2023. 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. In the third quarter of 2023, we changed the estimated useful lives of certain property and equipment within our completion services segment. See Note 1 of Notes to consolidated financial statements included as a part of Item 8 of this Report.

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, 2023:

Impairment of long-lived assets — We review our long-lived assets, including property and equipment, for impairment whenever events or changes in circumstances indicate that the carrying amounts of certain assets may not be recovered over their estimated remaining useful lives (“triggering events”). 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. This analysis is based on estimates such as management’s short-term and long-term forecast of operating performance, including revenue growth rates and expected profitability margins, customer attrition rates, contributory asset charges, estimates of the remaining useful life and service potential of the assets within the asset group, and a discount rate based on our weighted average cost of capital. We determined no triggering events occurred in 2023 related to our long-lived assets. See Note 6 of Notes to consolidated financial statements included as a part of Item 8 of this Report.

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.

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, and if that is the case, 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.

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.

During the fourth quarter of 2023, our share price experienced a sustained decline which resulted in a decrease to our market capitalization. This decline in share price was deemed a triggering event that warranted a quantitative assessment for goodwill impairment for all three of our reporting units.

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 utilizes present values of cash flows to estimate fair value. Forecasted cash flows considered known market conditions as of December 31, 2023, and management's anticipated business outlook for each reporting unit. Future cash flows were projected based on estimates of revenue, 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. The future cash flows were discounted using a market-participant, risk-adjusted weighted average cost of capital of 10% for the drilling products reporting unit and 12% for the completion services reporting unit. We estimated the fair value of the cementing services reporting unit using a market approach. The market approach was based on trading multiples of companies comparable to the cementing services reporting unit.

The forecast for the drilling products reporting unit assumes continued growth 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.

The forecast for the completion services reporting unit assumes activity in 2024 consistent with 2023 exit levels and moderate increases in activity of 3% to 5% beginning in 2025 and holding flat until the terminal period, which was consistent with rig count forecasts as of December 31, 2023. A sustained decrease in oil prices and rig count could negatively affect the key assumptions used in our goodwill assessment for completion services.

Based on the results of the goodwill impairment tests, the fair values of the drilling products, completion services, and cementing services reporting units exceeded their carrying values by approximately 4%, 11%, and 80%, respectively. Accordingly, no impairment was recorded for any of the 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 6%, while a 100 bps increase to our discount rate would reduce our estimated fair value by approximately 10%.

Assuming all changes are isolated, a decrease of 100 bps in our long-term revenue growth rate for our completion services reporting unit would reduce our estimated fair value by approximately 6%, while a 100 bps increase to our discount rate would reduce our estimated fair value by approximately 8%.

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.

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 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 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, 2023, 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. Crude oil prices and demand for drilling and completion equipment and services increased from 2021 to 2022, and industry supply of Tier-1, super-spec rigs became constrained. Commodity price volatility in the second quarter of 2023 resulted in a decline in industry activity, commodity prices subsequently increased during the third quarter before declining in the fourth quarter of 2023. The current demand for equipment and services remains dependent on 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 $78.53 per barrel in the fourth quarter of 2023. Natural gas prices (based on the Henry Hub Spot Market Price) averaged $2.74 per MMBtu in the fourth quarter of 2023.

Inflation rates have begun to moderate. However, we continue to actively monitor market trends primarily related to sourcing labor, supplies and equipment.

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.

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) from continuing operations plus income tax expense (benefit), net interest expense, depreciation, depletion, amortization and impairment expense 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) from continuing operations 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) from continuing operations. 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) from continuing operations.

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

As of December 31, 2023, we would have had exposure to interest rate market risk associated with any outstanding borrowings and letters of credit that we had under the Credit Agreement and amounts owed under the Reimbursement Agreement.

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 LIBOR rate plus 2.25% 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 and cash equivalents, trade receivables and accounts payable approximate fair value due to the short-term maturity of these items.

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.

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, 2023, 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.

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, 2023, 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, 2023.

We completed the Ulterra acquisition on August 14, 2023 and the NexTier merger on September 1, 2023. We excluded Ulterra’s and NexTier’s disclosure controls and procedures that are subsumed by their internal control over financial reporting from the scope of management’s assessment of the effectiveness of our disclosure controls and procedures. This exclusion is in accordance with the guidance issued by the Staff of the Securities and Exchange Commission that an assessment of recent business combinations may be omitted from management's assessment of internal control over financial reporting for one year following the acquisition. As a result of our integration of the Ulterra and NexTier disclosure controls and procedures, certain controls will be evaluated and may be changed. Ulterra and NexTier’s total revenues constituted approximately 3% and 26% of our consolidated revenues, respectively, for the year ended December 31, 2023. Ulterra’s and NexTier’s total assets constituted approximately 3% and 23% of our consolidated total assets, respectively, as of December 31, 2023.

The effectiveness of our internal control over financial reporting as of December 31, 2023 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.

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.

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.

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.

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.

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.

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.

The following exhibits are filed herewith or incorporated by reference herein. Our Commission file number is 0-22664.

* Management Contract or Compensatory Plan identified as required by Item 15(a)(3) of Form 10-K.

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, 2023 and 2022, 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, 2023, including the related notes and schedule of valuation and qualifying accounts for each of the three years in the period ended December 31, 2023 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, 2023, 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, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023 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, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

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.

As described in Management’s Report on Internal Control over Financial Reporting, management has excluded Ulterra Drilling Technologies, L.P. (Ulterra) and NexTier Oilfield Solutions Inc. (NexTier) from its assessment of internal control over financial reporting as of December 31, 2023, because they were business combinations during 2023. We have also excluded Ulterra and NexTier from our audit of internal control over financial reporting. Ulterra and NexTier are wholly-owned subsidiaries whose total assets and total revenues excluded from management’s assessment and our audit of internal control over financial reporting represent approximately 3% and 23% of total assets, respectively, and approximately 3% and 26% of total revenues, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2023.

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.

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are 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 matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

As described in Note 2 to the consolidated financial statements, on August 14, 2023, the Company completed the acquisition of Ulterra for total consideration transferred of $897 million. Of the acquired intangible assets, $245 million of customer relationships were recorded. Fair value was estimated by management using a multi-period excess earnings method for customer relationships. Management 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.

The principal considerations for our determination that performing procedures relating to the valuation of customer relationships acquired in the acquisition of Ulterra is a critical audit matter are (i) the significant judgment by management when developing the fair value estimate of the customer relationships acquired; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions related to cash flow projections, customer attrition rates, contributory asset charges, 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 the acquisition accounting, including controls over management’s valuation of the customer relationships acquired. These procedures also included, among others (i) reading the purchase agreement; (ii) testing management’s process for developing the fair value estimate of the customer relationships acquired; (iii) evaluating the appropriateness of the multi-period excess earnings method used by management; (iv) testing the completeness and accuracy of the underlying data used in the multi-period excess earnings method; and (v) evaluating the reasonableness of the significant assumptions used by management related to cash flow projections, customer attrition rates, contributory asset charges, and the discount rate. Evaluating management’s assumption related to cash flow projections involved considering (i) the current and past performance of the Ulterra business; (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 multi-period excess earnings method and (ii) the reasonableness of the customer attrition rates, contributory asset charges, and the discount rate assumptions.

Merger with NexTier – Valuation of Customer Relationships, Trade Name and Developed Technology

As described in Note 2 to the consolidated financial statements, on September 1, 2023, the Company completed the merger with NexTier for total consideration transferred of $2,799 million. Of the acquired intangible assets, $540 million of customer relationships, $85 million of a trade name, and $143 million of developed technology were recorded. Fair value was estimated by management using a multi-period excess earnings method for the customer relationships and a relief from royalty method for the trade name and developed technology. Management 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.

The principal considerations for our determination that performing procedures relating to the valuation of the customer relationships, trade name and developed technology acquired in the merger with NexTier is a critical audit matter are (i) the significant judgment by management when developing the fair value estimate of the customer relationships, trade name and developed technology acquired; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant

assumptions related to cash flow projections, customer attrition rates, contributory asset charges, royalty rates, and the discount rate for the customer relationships, cash flow projections and the royalty rate for the trade name, and cash flow projections and the royalty rate for the developed technology; 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 the acquisition accounting, including controls over management’s valuation of the customer relationships, trade name and developed technology acquired. These procedures also included, among others (i) reading the merger agreement; (ii) testing management’s process for developing the fair value estimate of the customer relationships, trade name and developed technology acquired; (iii) evaluating the appropriateness of the multi-period excess earnings and relief from royalty methods used by management; (iv) testing the completeness and accuracy of the underlying data used in the multi-period excess earnings and relief from royalty methods; and (v) evaluating the reasonableness of the significant assumptions used by management related to cash flow projections, customer attrition rates, contributory asset charges, royalty rates, and the discount rate for the customer relationships, cash flow projections and the royalty rate for the trade name, and cash flow projections and the royalty rate for the developed technology. Evaluating management’s assumption related to cash flow projections for the customer relationships, trade name and developed technology involved considering (i) the current and past performance of the NexTier business; (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 multi-period excess earnings and relief from royalty methods and (ii) the reasonableness of the customer attrition rates, contributory asset charges, royalty rates, and the discount rate assumptions for the customer relationships and the royalty rate assumption for the trade name and developed technology.

The accompanying notes are an integral part of these 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”). Ulterra is 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”). 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. See Note 2 for additional details on the acquisition and merger.

In the fourth quarter of 2021, we completed the acquisition of Pioneer Energy Services Corp. (“Pioneer”). Pioneer provided land-based contract drilling services and production services to a diverse group of oil and natural gas exploration and production companies in the United States and internationally in Colombia. The purchase price allocation was finalized in 2022. The measurement period adjustments did not have a material impact on our consolidated financial statements.

On December 31, 2021, we completed the sale of the acquired Pioneer well servicing rig business and wireline business to Clearwell Dynamics, LLC. The sale price was $43.0 million in cash consideration, subject to customary purchase price adjustments at closing for cash and working capital. The results of operations of these businesses were presented as a discontinued operation during the fourth quarter of 2021.

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 significant 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. These reclassifications include the change in our reportable segments in 2023. 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. Accordingly, we recast our results of operations for all years presented to align with our revised reportable segments. These reclassifications had no effect on our previously reported operating and net income (loss) within our consolidated statements of operations or cash flows from operating, investing and financing activities within our consolidated statements of cash flows.

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 include the results of Ulterra from August 14, 2023 to December 31, 2023, and the results of NexTier from September 1, 2023 to December 31, 2023.

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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 sheet that sum to the total of such amounts shown in the statement of cash flows for the years ended December 31, 2023 and 2022:


	Year Ended December 31,
	2023		2022
Cash and cash equivalents	$	190,108	$	137,553
Restricted cash		2,572		—
Total cash, cash equivalents and restricted cash	$	192,680	$	137,553

Revenue recognition — Revenues from our drilling services, completion services, drilling products, and other activities are recognized as services are performed. All of the wells we drilled in 2023, 2022 and 2021 were drilled under daywork contracts. 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.

As a result of the Ulterra acquisition, our revenues now include a significant amount of rental revenue included within the new “Drilling products” segment. See Note 3 for details.

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. As inventory is consumed, expense is recorded in direct operating cost in the consolidated statements of operations using the weighted average cost method for non-manufacturing inventory and standard cost method for manufacturing inventory.

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, excess volume on-hand 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 $31.0 million and $34.6 million at December 31, 2023 and 2022, 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 method of depreciation does not change whenever property and equipment become idle.

F-11

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.

Oil and natural gas properties — Working interests in oil and natural gas properties are accounted for using the successful efforts method of accounting. Under the successful efforts method of accounting, exploration costs which result in the discovery of oil and natural gas reserves and all development costs are capitalized to the appropriate well. Exploration costs which do not result in discovering oil and natural gas reserves are charged to expense when such determination is made. Costs of exploratory wells are initially capitalized to wells-in-progress until the outcome of the drilling is known. We review wells-in-progress quarterly to determine whether sufficient progress is being made in assessing the reserves and economic viability of the respective projects. If no progress has been made in assessing the reserves and economic viability of a project after one year following the completion of drilling, we consider the well costs to be impaired and recognize the costs as expense. Geological and geophysical costs, including seismic costs, and costs to carry and retain undeveloped properties are charged to expense when incurred. The capitalized costs of both developmental and successful exploratory type wells, consisting of lease and well equipment and intangible development costs, are depreciated, depleted and amortized using the units-of-production method, based on engineering estimates of total proved developed oil and natural gas reserves for each respective field. Oil and natural gas leasehold acquisition costs are depreciated, depleted and amortized using the units-of-production method, based on engineering estimates of total proved oil and natural gas reserves for each respective field.

We review our proved oil and natural gas properties for impairment whenever a triggering event occurs, such as downward revisions in reserve estimates or decreases in expected future oil and natural gas prices. Proved properties are grouped by field and undiscounted cash flow estimates are prepared based on management’s expectation of future pricing over the lives of the respective fields. These cash flow estimates are reviewed by an independent petroleum engineer. If the net book value of a field exceeds our undiscounted cash flow estimate, impairment expense is measured and recognized as the difference between net book value and fair value. The fair value estimates used in measuring impairment are based on internally developed unobservable inputs including reserve volumes and future production, pricing and operating costs (Level 3 inputs in the fair value hierarchy of fair value accounting). We review unproved oil and natural gas properties quarterly to assess potential impairment. Our impairment assessment is made on a lease-by-lease basis and considers factors such as management’s intent to drill, lease terms and abandonment of an area. If an unproved property is determined to be impaired, the related property costs are expensed. Impairment expense related to oil and natural gas properties of approximately $7.0 million, $4.5 million and $1.3 million was recorded for the years ended December 31, 2023, 2022 and 2021, respectively.

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 would recognize an impairment in an amount equal to the excess, limited to the total amount of goodwill allocated to the reporting unit. See Note 7 for details.

F-12

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. Renewal options are included in the right-of-use asset and lease liability if it is reasonably certain that we will exercise the option, and termination options are included in the right-of-use asset and lease liability if it is not reasonably certain 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.

In the third quarter of 2023, as part of the Ulterra acquisition and the NexTier merger, we acquired operating and finance leases. We inherited NexTier’s and Ulterra’s lease classifications as of the time of each respective acquisition. We have 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.

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. We include the term of any renewal option for the right-of-use asset and lease liability if it is reasonably certain that we will exercise the option. We also include the term of any termination option for the right-of-use asset and lease liability if it is not reasonably certain 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.

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 has 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 2023 and 2022.

Change in Accounting Estimate — In the third quarter of 2023, we changed the estimated useful lives of certain property and equipment within our completion services segment. The change in the estimated useful lives was necessitated by recent trends in increased intensity and pumping hours per day of certain components used in servicing larger jobs. We determined the estimated useful life of fluid ends is now less than one year, which results in these components no longer being capitalized to property and equipment but instead recorded to inventory and expensed as direct operating costs as they are consumed. Additionally, we shortened the estimated useful lives of certain other completion components that remain in property and equipment, which resulted in a decrease in the weighted average estimated useful lives of these assets from nine years to seven years. The effect of our change in estimated useful lives of these assets was a decrease in operating income of $30.7 million and a decrease in net income of $24.3 million for the year ended December 31, 2023, which resulted in a decrease in basic and diluted earnings per share of $0.09 and $0.09 per share, respectively.

F-13

Recently Adopted Accounting Standards — In October 2021, the FASB issued an accounting standards update, which requires contract assets and contract liabilities (i.e., deferred revenue) acquired in a business combination to be recognized and measured by the acquirer on the acquisition date in accordance with ASC 606, Revenue from Contracts with Customers. Generally, this new guidance will result in the acquirer recognizing contract assets and contract liabilities at the same amounts recorded by the acquiree. Historically, such amounts were recognized by the acquirer at fair value in acquisition accounting. The amendments should be applied prospectively to acquisitions occurring on or after the effective date. The amendments in the update are effective for public business entities for fiscal years beginning after December 15, 2022, with early adoption permitted. We adopted this new guidance on January 1, 2023, and there was no material impact on our consolidated financial statements.

Recently Issued Accounting Standards — In March 2020, the FASB issued an accounting standards update to provide temporary optional expedients that simplify the accounting for contract modifications to existing debt agreements expected to arise from the market transition from LIBOR to alternative reference rates. The amendments in the update are effective as of March 12, 2020 through December 31, 2022 and may be applied to contract modifications from the beginning of an interim period that includes or is subsequent to March 12, 2020. In December 2022, the FASB issued an update, which deferred the sunset date to December 31, 2024. We do not expect this new guidance will have a material impact on our consolidated financial statements.

In November 2023, the FASB issued an accounting standards update to improve reportable segment disclosure requirements and enhance disclosures about significant segment expenses. The amendments in the update are effective for public business entities for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024 on a retrospective basis. We are currently evaluating the effect of this pronouncement on our disclosures.

In December 2023, the FASB issued an accounting standards update to improve income tax disclosure requirements. The amendments in the update are effective for public business entities for fiscal years beginning after December 15, 2024 and should be applied prospectively. We are currently evaluating the effect of this pronouncement on our disclosures.

2. Acquisitions and Discontinued Operations

Pioneer Energy Services Corp.

On October 1, 2021, we completed the acquisition of Pioneer by acquiring 100% of its equity interests. Total consideration for the acquisition included the issuance of approximately 26.3 million shares of our common stock and payment of $30 million cash, which based on the closing price of our common stock of $9.44 on October 1, 2021, valued the transaction at approximately $278 million.

Pioneer provided land-based contract drilling services and production services to a diverse group of oil and natural gas exploration and production companies in the United States and internationally in Colombia.

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

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


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

Approximately $41.5 million of revenues and $30.5 million of direct operating expenses attributed to the Pioneer acquisition are included in our consolidated statements of operations for the period from the closing date on October 1, 2021 through December 31, 2021, excluding the acquired well servicing rig business and the wireline businesses that have been presented as a discontinued operation in our consolidated statements of operations. Revenues and direct operating expenses for our discontinued operations are presented below. During 2021, we incurred costs related to the Pioneer acquisition totaling $12.1 million, which are included in our consolidated statements of operations as “Merger and integration expenses.”

Pro Forma

The results of Pioneer’s operations since the Pioneer merger date of October 1, 2021, are included in our consolidated statements of operations. The following pro forma condensed combined financial information was derived from our and Pioneer’s historical financial

F-14

statements, excluding the well servicing rig business and wireline business that were disposed on December 31, 2021, and gives effect to the acquisition as if it had occurred on January 1, 2020. 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 fair value of acquired fixed assets, (ii) removal of the historical interest expense, loss on debt extinguishment and reorganization expenses of the acquired entities and (iv) the tax benefit of the aforementioned pro forma adjustments.

The pro forma results of operations do not include any cost savings or other synergies that may result from the Pioneer acquisition. The pro forma results of operations also do not include any estimated costs that have been or will be incurred to integrate Pioneer operations. The pro forma results of operations include our merger and integration-related costs of $12.1 million and Pioneer’s merger related costs of $4.6 million for the year ended December 31, 2021.

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 Pioneer acquisition taken place on January 1, 2020; 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):


	2021
	(Unaudited)
Revenues	$	1,464,351
Net loss	$	(666,032	)

Discontinued Operations

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

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


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

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

Total other income (expense)		64

Income from discontinued operations before income taxes		2,534

Income tax benefit		—

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

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 $376 million of cash, which based on the closing price of our common stock of $14.94 on August 14, 2023, valued the transaction at closing at approximately $897 million.

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

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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 (1)		375,740
Total consideration transferred	$	897,146

(1)

Net cash consideration included $370 million cash consideration as adjusted for customary purchase price adjustments set forth in the Ulterra merger agreement relating to cash, net working capital, indebtedness and transaction expenses of Ulterra as of the closing. The adjustment is subject to a post-closing target net working capital adjustment in accordance with the Ulterra merger agreement.

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. Certain data necessary to complete the purchase price allocation is not yet available, including final tax returns that provide the underlying tax basis of Ulterra’s assets and liabilities. The measurement period adjustments in the fourth quarter of 2023 did not have a material impact on our consolidated financial statements. We will complete the purchase price allocation during the 12-month period following the acquisition date.

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		14,274
Total assets acquired		599,859

Liabilities assumed:
Accounts payable		23,258
Accrued liabilities		31,608
Operating lease liability		7,513
Finance lease liability		5,228
Deferred tax liabilities		83,993
Total liabilities assumed		151,600
Less: noncontrolling interest		(8,729	)
Net assets acquired		439,530
Goodwill		457,616
Total consideration transferred	$	897,146

(1)

We recorded an 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.

F-16

(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. During the twelve months ended December 31, 2023, we incurred costs related to the Ulterra acquisition totaling $5.6 million, 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:


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

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.

F-17

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 has been 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.

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. Certain data necessary to complete the purchase price allocation is not yet available, including final tax returns that provide the underlying tax basis of NexTier’s assets and liabilities. The measurement period adjustments in the fourth quarter of 2023 did not have a material impact on our consolidated financial statements. We will complete the purchase price allocation during the 12-month period following the acquisition date.

The following table summarizes the fair values of the assets acquired and liabilities assumed at the date of the merger:

F-18


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 $262.7 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 Energy, Inc. 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. The goodwill is not deductible for tax purposes. 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, 2023, we incurred costs related to the NexTier merger totaling $92.5 million, 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:


	Fair Value		Weighted Average Useful Life
	(in thousands)		(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.

F-19

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

6. Property and Equipment

Property and equipment consisted of the following at December 31, 2023 and 2022 (in thousands):


	2023			2022
Equipment	$	8,506,727		$	7,551,099
Oil and natural gas properties		238,337			236,156
Buildings		248,693			175,212
Rental equipment		119,653			—
Land		38,811			23,610
Total property and equipment		9,152,221			7,986,077
Less accumulated depreciation, depletion, amortization and impairment		(5,811,809	)		(5,725,501	)
Property and equipment, net	$	3,340,412		$	2,260,576

F-21

Depreciation, depletion, amortization and impairment — The following table summarizes depreciation, depletion, amortization and impairment expense related to property and equipment and intangible assets for 2023, 2022 and 2021 (in thousands):


	2023		2022		2021
Depreciation and impairment expense	$	682,672	$	472,969	$	818,999
Amortization expense		41,521		2,891		24,606
Depletion expense		7,223		8,085		5,573
Total	$	731,416	$	483,945	$	849,178

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 abandoned. There were no impairments in 2022 or 2023. In the fourth quarter of 2021, we identified 43 legacy non-super-spec rigs and equipment to be abandoned. Based on the strong customer preference across the industry for super-spec drilling rigs, we believed the 43 rigs that were abandoned had limited commercial opportunity. We recorded a $220 million charge related to this abandonment in the fourth quarter of 2021.

We also periodically evaluate our other drilling service assets. In the fourth quarter of 2021, we abandoned certain directional drilling equipment totaling $2.5 million and recorded a charge on our developed technology intangible asset of $11.4 million due to advances in technology that rendered those assets, and their related spare parts inventory, obsolete. There were no similar charges in 2022 or 2023.

We also 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 abandoned. In the fourth quarter of 2021, we recorded a charge of $32.2 million related to the abandonment of approximately 0.2 million horsepower within our completion services fleet. The majority of these units were frac pumps but also included pump down units. These units were abandoned due to changes in customer preferences for dual fuel, advancements in technology, and prohibitive reactivation costs. There were no similar charges in 2022 or 2023.

We also periodically evaluate our drilling products 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. There have been no impairment charges recorded since the acquisition of these assets as part of the Ulterra acquisition in the third quarter of 2023.

7. Goodwill and Intangible Assets

Goodwill — We had no goodwill balance as of December 31, 2022. As a result of both the Ulterra acquisition and the NexTier merger in 2023, we recognized 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, and if that is the case, 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.

Goodwill Impairment Assessment

F-22

unit. Future cash flows were projected based on estimates of revenue, 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. The future cash flows were discounted using a market-participant, risk-adjusted weighted average cost of capital of 10% for the drilling products reporting unit and 12% for the completion services reporting unit. We estimated the fair value of the cementing services reporting unit using a market approach. The market approach was based on trading multiples of companies comparable to the cementing services reporting unit.

Goodwill by operating segment as of December 31, 2022 and 2023 and changes for the years then ended are as follows (in thousands):


	Completion		Drilling
	Services		Products		Total
Balance, December 31, 2022	$	—	$	—	$	—
Goodwill acquired		921,656		451,341		1,372,997
Measurement period adjustment		469		6,275		6,744
Balance, December 31, 2023	$	922,125	$	457,616	$	1,379,741

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:


		Weighted Average
	Segment	Useful Life
		(in years)
Customer relationships	Drilling Services, Completion Services and Drilling Products		11.1
Developed technology	Drilling Services, Completion Services and Drilling Products		4.6
Trade name	Completion Services and Drilling Products		9.7
Other	Drilling Services and Completion Services		1.8

During 2021, we achieved certain internal advancements in our directional drilling technology that have rendered obsolete certain technology acquired as part of the MS Directional acquisition. Accordingly, we recorded a charge of $11.4 million to abandon these developed technology intangibles and certain related internal use software.

The gross carrying amount and accumulated amortization of intangible assets as of December 31, 2023 and 2022 are as follows (in thousands):


	2023							2022
	Gross Carrying		Accumulated			Net Carrying		Gross Carrying		Accumulated			Net Carrying
	Amount		Amortization			Amount		Amount		Amortization			Amount
Customer relationships	$	786,715	$	(25,563	)	$	761,152	$	1,800	$	(1,071	)	$	729
Developed technology		202,772		(16,435	)		186,337		7,772		(3,773	)		3,999
Trade name		101,000		(3,406	)		97,594		—		—			—
Other		7,345		(731	)		6,614		1,450		(333	)		1,117
Intangible assets, net	$	1,097,832	$	(46,135	)	$	1,051,697	$	11,022	$	(5,177	)	$	5,845

Amortization and impairment expense on intangible assets of approximately $41.5 million, $1.3 million, and $24.0 million was recorded for the years ended December 31, 2023, 2022 and 2021, respectively, which included an $11.4 million impairment in 2021.

F-23

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,
2024	$	121,307
2025		121,039
2026		120,702
2027		120,674
2028		105,481
Thereafter		456,608
Total	$	1,045,811

9. Long-Term Debt

Long-term debt consisted of the following at December 31, 2023 and 2022 (in thousands):


	Effective Interest Rate	December 31, 2023			December 31, 2022
3.95% Senior Notes Due 2028	4.03%		482,505		$	488,505
5.15% Senior Notes Due 2029	5.26%		344,895			347,900
7.15% Senior Notes Due 2033	7.28%		400,000			—
Equipment Loans Due 2025	5.25%		18,686			—
			1,246,086			836,405
Less deferred financing costs and discounts			(8,919	)		(5,468	)
Less current portion			(12,226	)		—
Total			1,224,941		$	830,937

Credit Agreement — On August 29, 2023, we entered into Amendment No. 4 to Amended and Restated Credit Agreement (the “Credit Agreement Amendment”), which amended our Amended and Restated Credit Agreement, dated as of March 27, 2018 (as amended, the “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 Credit Agreement Amendment, among other things, (i) deemed certain outstanding letters of credit issued for the account of BEP Diamond Holdings Corp. (the entity we acquired in the Ulterra acquisition) with a face amount of $2.5 million to have been issued under the Credit Agreement and (ii) extended the maturity date for $85 million of revolving credit commitments of certain lenders under the Credit Agreement from March 27, 2025 to March 27, 2026. As a result, of the $600 million of revolving credit commitments under the Credit Agreement, the maturity date for $501.7 million of such commitments is March 27, 2026; the maturity date for $48.3 million of such commitments is March 27, 2025; and the maturity date for the remaining $50 million of such commitments is March 27, 2024.

F-24

2015 Reimbursement Agreement — On March 16, 2015, we entered into a Reimbursement Agreement (the “Reimbursement Agreement”) with The Bank of Nova Scotia (“Scotiabank”), pursuant to which we may from time to time request that Scotiabank issue an unspecified amount of letters of credit. As of December 31, 2023, we had $87.7 million in letters of credit outstanding under the Reimbursement Agreement.

2028 Senior Notes, 2029 Senior Notes and 2033 Senior Notes —On January 19, 2018, we completed an offering of $525 million in aggregate principal amount of our 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 our 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 our 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 revolving credit facility.

F-25

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.

Equipment Loans — As part of the NexTier merger, we assumed the obligations of NexTier Completions Solutions Inc. (“NCS”) under a Master Loan and Security Agreement (as amended, the “Master Agreement”) with Caterpillar Financial Services Corporation. The Master Agreement allows NCS to enter into secured equipment financing term loans from time to time (the “Equipment Loans”). The Equipment Loans may be drawn in multiple tranches, with each loan evidenced by a separate promissory note. The Master Agreement and the Equipment Loans contain customary affirmative and negative covenants, including limitations on further encumbrance of the collateral other than the applicable loans under the Master Agreement. We were in compliance with these covenants at December 31, 2023. The Equipment Loans bear interest at a rate of 5.25% per annum, and we pay interest on the 1st of each month. The Equipment Loans will mature on June 1, 2025.

Drilling Products Letters of Credit — As part of the Ulterra merger, we assumed letters of credit of $2.5 million outstanding with financial institutions providing for short-term borrowing capacity, overdraft protection and bonding requirements. We maintain these letters of credit primarily for compliance with contractual obligations. These letters of credit expire annually at various times during the year and are typically renewed. As of December 31, 2023, no amounts had been drawn under the letters of credit.

F-26

Presented below is a schedule of the principal repayment requirements of long-term debt by fiscal year as of December 31, 2023 (in thousands):


Year ending December 31,
2024	$	12,290
2025		6,396
2026		—
2027		—
2028		482,505
2029		344,895
Thereafter		400,000
Total	$	1,246,086

10. Commitments, Contingencies and Other Matters

Commitments – As of December 31, 2023, we maintained letters of credit in the aggregate amount of $92.4 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, 2023, no amounts had been drawn under the letters of credit.

As of December 31, 2023, we had commitments to purchase major equipment totaling approximately $153 million.

Our completion services segment has entered into agreements to purchase minimum quantities of proppants from certain vendors. We purchased $135 million, $93.0 million and $66.9 million of proppants under take-or-pay or similar agreements during the years ended December 31, 2023, 2022 and 2021, respectively. As of December 31, 2023, the remaining minimum obligation under these agreements was approximately $39.7 million, of which approximately $33.7 million, $4.0 million and $2.0 million relate to the remainder of 2024, 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.

F-27

million per occurrence deductible on our workers’ compensation insurance coverage, a $1.0 million per occurrence deductible on our equipment insurance coverage, a $10.0 million per occurrence deductible on our general liability coverage, and, for our automobile insurance coverage, a per occurrence deductible ranging from $2.0 million to $10.0 million. We also self-insure a number of risks, including loss of earnings and business interruption and most cybersecurity risks, and we do not carry a significant amount of insurance to cover risks of underground reservoir damage.

Other Matters — We have a Change in Control Agreement with one of our Executive Vice Presidents (the “Specified Employee”). The Change in Control Agreement generally has an initial term with automatic twelve-month renewals unless we notify the Specified Employee at least ninety days before the end of such renewal period that the term will not be extended. If a change in control occurs during the term of the agreement and the Specified Employee’s employment is terminated (i) by us other than for cause or other than automatically as a result of death, disability or retirement, or (ii) by the Specified Employee for good reason (as those terms are defined in the Change in Control Agreement), then the Specified Employee shall generally be entitled to, among other things:

•

a bonus payment equal to the highest bonus paid after the Change in Control Agreement was entered into (such bonus payment prorated for the portion of the fiscal year preceding the termination date);

•

a payment equal to 2 times the sum of (i) the highest annual salary in effect for such Specified Employee and (ii) the average of the three annual bonuses earned by the Specified Employee for the three fiscal years preceding the termination date and

•

continued coverage under our welfare plans for up to two years.

The Change in Control Agreement provides the Specified Employee with a full gross-up payment for any excise taxes imposed on payments and benefits received under the Change in Control Agreements or otherwise, including other taxes that may be imposed as a result of the gross-up payment.

We have Employment Agreements with our Chief Executive Officer, Chief Financial Officer, Chief Business Officer and General Counsel. Each Employment Agreement generally has an initial three-year term, subject to automatic annual renewal. The executive may terminate his employment under his Employment Agreement by providing written notice of such termination at least 30 days before the effective date of such termination. Under specified circumstances, we may terminate the executive’s employment under his Employment Agreement for Cause (as defined in the Employment Agreement) by providing written notice 10 - 30 days, depending on the nature of the cause trigger, before the effective date of such termination and granting at least 10 - 20 days, depending on the nature of the cause trigger, to cure the cause for such termination or (ii) by providing written notice of such termination at least 30 days before the effective date of such termination and by granting at least 20 days to cure the cause for such termination, provided that if the matter is reasonably determined by us to not be capable of being cured, the executive may be terminated for cause on the date the written notice is delivered. The Employment Agreement also provides for, among other things, severance payments and the continuation of certain benefits following our decision to terminate the executive other than for Cause, or termination by the executive for Good Reason (as defined in each Employment Agreement). Under these provisions, if the executive’s employment is terminated by us without Cause, or the executive terminates his employment for Good Reason:

•

the executive will have the right to receive a lump-sum payment consisting of 3 times (in the case of the Chief Executive Officer) or 2.5 times (in the case of the Chief Financial Officer, Chief Business Officer and General Counsel) the sum of (i) his base salary and (ii) the average annual cash bonus received by him for the three years prior to the date of termination;

•

the executive will have the right to receive a pro-rated lump-sum payment equal to his annual cash bonus based on actual results for the year, payable at the same time as annual cash bonuses are paid to active employees;

•

we will accelerate vesting of all time-based equity, phantom equity and long-term cash incentive awards on the 60th day following the executive’s termination and will cause all performance-based equity, phantom equity and long-term cash incentive awards to continue in effect through the end of the applicable performance period and vest based on actual results as if the executive had remained employed through the end of the applicable performance period; and

•

we will pay the executive certain accrued obligations and certain obligations pursuant to the terms of employee benefit plans.

If our decision to terminate other than for Cause or by the executive for Good Reason occurs following a Change in Control (as defined in his Employment Agreement, the executive will generally be entitled to the same severance payments and benefits described above except that the pro-rated lump-sum payment for annual cash bonuses will be based on his highest annual cash bonus for the last three years, and the executive will be entitled to 36 months (in the case of the Chief Executive Officer) or 30 months (in the case of the Chief Financial Officer, Chief Business Officer and General Counsel) of subsidized benefits continuation coverage.

F-28

Additionally, our Chief Business Officer is party to a letter agreement with us, which was entered into in connection with the closing of the NexTier merger. The letter agreement provides that, following the one-year anniversary of the closing of the NexTier merger, our Chief Business Officer will not have Good Reason (as defined in his Employment Agreement) to terminate his employment with us due to the transition of his role in connection with the NexTier merger and any resulting changes in his authority, duties or responsibilities. The letter agreement also provides a $2 million cash retention bonus, payable in eight quarterly installments following the closing of the NexTier merger, subject to our Chief Business Officer’s continued employment in good standing with us on each applicable payment date. Any unpaid portions of the retention bonus will become payable if our Chief Business Officer’s employment is terminated by us without cause or by our Chief Business Officer for Good Reason (unless, within six months of the closing of the NexTier merger, our Chief Business Officer resigns for Good Reason as a result of the transition of his role, in which case the full amount of the retention bonus will be forfeited with any previously paid portions offset against any severance amounts payable to our Chief Business Officer).

11. Stockholders’ Equity

Cash Dividend — On February 14, 2024, 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 15, 2024 to holders of record as of March 1, 2024. The amount and timing of all future dividend payments, if any, are subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of our debt agreements and other factors. Our Board of Directors may, without advance notice, reduce or suspend our dividend to improve our financial flexibility and position our company for long-term success. There can be no assurance that we will pay a dividend in the future.

Share Repurchases and Acquisitions — In September 2013, our Board of Directors approved a stock buyback program. In April 2023, our Board of Directors approved an increase of the authorization under the stock buyback program to allow for an aggregate of $300 million 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, 2023, we had remaining authorization to purchase approximately $206 million of our outstanding common stock under the 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 billion of future share repurchases. Shares of stock purchased under the buyback program are held as treasury shares.

Treasury stock acquisitions during the years ended December 31, 2023, 2022 and 2021 were as follows (dollars in thousands):


	2023				2022				2021
	Shares		Cost		Shares		Cost		Shares		Cost
Treasury shares at beginning of period		88,758,722	$	1,453,079		84,128,995	$	1,372,641		83,402,322	$	1,366,313
Purchases pursuant to stock buyback program		14,086,229		168,631		3,254,599		57,173		—		—
Acquisitions pursuant to long-term incentive plan		2,735,060		35,965		1,372,101		23,237		451,196		3,727
Purchases in connection with Pioneer acquisition		—		—		—		—		275,477		2,601
Other		—		—		3,027		28		—		—
Treasury shares at end of period		105,580,011	$	1,657,675		88,758,722	$	1,453,079		84,128,995	$	1,372,641

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

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. Subject to stockholder approval, our Board of Directors approved an amendment to the 2021 Plan to increase the number of shares available for issuance under the 2021 Plan by 5.445 million shares (the “First Amendment”). On June 8, 2023, our stockholders approved the First Amendment. On September 1, 2023, in connection with the NexTier merger, our Board of Directors approved a second amendment to the 2021 Plan (the “Second Amendment,” and together with the First Amendment, the “2021 Plan Amendments”) to assume approximately 10 million shares previously reserved for issuance under the NexTier Oilfield Solutions Inc. Equity and Incentive Award Plan (the “NexTier Plan”). Following the 2021 Plan Amendments, the aggregate number of shares of Common Stock authorized for grant under the 2021 Plan is approximately 29.0 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 equity awards in respect of shares of Patterson-UTI Energy, Inc. common stock.

The aggregate number of shares of Common Stock authorized for grant under the 2021 Plan is approximately 29.0 million, which includes approximately 4.9 million shares previously authorized for issuance under our 2014 Plan and approximately 10 million shares assumed from the NexTier merger.

Our share-based compensation plans at December 31, 2023 are as follows:


	Shares		Shares Underlying		Shares
	Authorized		Awards		Available
Plan Name	for Grant		Outstanding		for Grant
2021 Plan		28,963,412		5,004,289		13,910,294
NexTier Plan		—		2,660,633		—
Former C&J Energy Plan		—		789,337		—
2014 Plan		—		2,571,965		—

A summary of the 2021 Plan follows:

•

The Compensation Committee of the Board of Directors administers the 2021 Plan other than the awards to directors.

•

All employees, officers and directors are eligible for awards.

•

The Compensation Committee determines the vesting schedule for awards. Awards typically vest over one year for non-employee directors and three years for employees.

•

The Compensation Committee sets the term of awards and no option term can exceed 10 years.

•

The 2021 Plan provides that the total compensation paid to each non-employee director for their service as such, whether in cash or in equity awards under the 2021 Plan (based on the grant date fair value of any such awards) during a single fiscal year may not exceed $750,000; however, the foregoing limit will instead be $1,000,000 for any fiscal year in which the non-employee director is first appointed to the Board of Directors or any fiscal year in which the non-employee director serves as chairman or lead director.

•

All options granted under the 2021 Plan are granted with an exercise price equal to or greater than fair market value of our common stock at the time the option is granted.

•

The 2021 Plan provides for awards of incentive and non-incentive stock options, stock appreciation rights (“SARs”), restricted stock awards, other stock unit awards, performance share awards, performance unit awards and dividend equivalent rights.

Options granted under the 2014 Plan typically vested over one year for non-employee directors and three years for employees. All options were granted with an exercise price equal to the fair market value of the related common stock at the time of grant.

F-30

Stock Options — We estimate the grant date fair values of stock options using the Black-Scholes-Merton valuation model. Volatility assumptions are based on the historic volatility of our common stock over the most recent period equal to the expected term of the options as of the date such options are granted. The expected term assumptions are based on our experience with respect to employee stock option activity. Dividend yield assumptions are based on the expected dividends at the time the options are granted. The risk-free interest rate assumptions are determined by reference to United States Treasury yields. No options were granted during the years ended December 31, 2023, 2022 and 2021.

Stock option activity for the year ended December 31, 2023 follows:


				Weighted Average
	Shares			Exercise Price Per Share
Outstanding at beginning of year		2,905,150		$	22.19
Assumed (1)		652,573		$	27.97
Exercised		—		$	—
Expired		(692,500	)	$	22.82
Outstanding at end of year		2,865,223		$	23.36
Exercisable at end of year		2,865,223		$	23.36

(1)

Awards assumed in connection with the NexTier merger. All of these assumed awards had been previously granted by NexTier under the NexTier Plan or the Former C&J Energy Plan, in periods prior to the NexTier merger.

Options outstanding and exercisable at December 31, 2023 have no intrinsic value and a weighted-average remaining contractual term of 1.69 years. Additional information with respect to options granted, vested and exercised during the years ended December 31, 2023, 2022 and 2021 follows (in thousands, except per share data):


	2023		2022		2021
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	$	—	$	—	$	89
Aggregate intrinsic value of stock options exercised	$	—	$	410	$	—

As of December 31, 2023, 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, 2023 follows:


							Weighted Average
	Time			Performance			Grant Date Fair
	Based			Based			Value Per Share
Non-vested restricted stock units outstanding at beginning of year		3,090,846			359,315		$	12.71
Granted		1,840,861			165,276		$	11.60
Assumed (1)		7,438,031			—		$	5.62
Vested		(6,379,970	)		—		$	5.95
Forfeited		(162,100	)		(3,058	)	$	13.78
Non-vested restricted stock units outstanding at end of year		5,827,668			521,533		$	10.60

(1)

As of December 31, 2023, approximately 6.1 million non-vested restricted stock units outstanding are expected to vest. Additional information as of December 31, 2023 with respect to these non-vested restricted stock units follows (dollars in thousands):


Aggregate intrinsic value	$	65,937
Weighted-average remaining vesting period	1.63 years
Unrecognized compensation cost	$	51,434

F-31

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, 2023, $2.4 and $6.2 million are included in “Accrued Liabilities” and “Other Liabilities” in our consolidated balance sheets, respectively. We recognized $5.0 million of compensation expense for these awards during the year ended December 31, 2023.

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.

The performance goals for the Performance Units are tied to our total shareholder return for the performance period as compared to total shareholder return for a peer group determined by the Compensation Committee. For the performance units granted in April 2021 and April 2022, the peer group includes three market indices and one market index, respectively. The performance goals are considered to be market conditions under the relevant accounting standards and the market conditions were factored into the determination of the fair value of the respective Performance Units. The recipients will receive the target number of shares if our total shareholder return during the performance period, when compared to the peer group, is at the 55th percentile. If our total shareholder return during the performance period, when compared to the peer group, is at the 75th percentile or higher, then the recipients will receive two times the target number of shares. If our total shareholder return during the performance period, when compared to the peer group, is at the 25th percentile, then the recipients will only receive one-half of the target number of shares. If our total shareholder return during the performance period, when compared to the peer group, is between the 25th and 55th percentile, or the 55th and 75th percentile, then the shares to be received by the recipients will be determined using linear interpolation for levels of achievement between these points. The payout under the 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 2018-2023 is set forth below:


	2023		2022		2021		2020		2019		2018
	Performance		Performance		Performance		Performance		Performance		Performance
	Unit Awards		Unit Awards		Unit Awards		Unit Awards		Unit Awards		Unit Awards
Target number of shares		631,700		414,000		843,000		500,500		489,800		310,700

In April 2021, 621,400 shares were issued to settle the 2018 Performance Units. In April 2022, 979,600 shares were issued to settle the 2019 Performance Units. In May 2023, 1,001,000 shares were issued to settle the 2020 Performance Units. The Performance Units granted in 2021, 2022 and 2023 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):


	2023		2022		2021		2020		2019		2018
	Performance		Performance		Performance		Performance		Performance		Performance
	Unit Awards		Unit Awards		Unit Awards		Unit Awards		Unit Awards		Unit Awards
Aggregate fair value at date of grant	$	8,440	$	10,743	$	7,225	$	826	$	9,958	$	8,004

The weighted-average fair value calculations for performance units granted during the years ended December 31, 2023, 2022 and 2021 were based on the following weighted-average assumptions set forth below:


	2023			2022			2021
Risk-free interest rate (1)		3.6	%		2.9	%		0.4	%
Expected stock volatility (2)		72.1	%		86.5	%		83.2	%
Expected dividend yield (3)		3.0	%		1.0	%		1.3	%
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.

F-32

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):


	2023		2022		2021		2020		2019		2018
	Performance		Performance		Performance		Performance		Performance		Performance
	Unit Awards		Unit Awards		Unit Awards		Unit Awards		Unit Awards		Unit Awards
Year ended December 31, 2023	$	2,248	$	3,749	$	2,426	$	69	NA		NA
Year ended December 31, 2022	NA		$	2,686	$	2,408	$	275	$	830	NA
Year ended December 31, 2021	NA		NA		$	1,806	$	275	$	3,319	$	667

As of December 31, 2023, we had unrecognized compensation cost of $11.1 million related to our unvested Performance Units. The weighted-average remaining vesting period for these unvested Performance Units was 1.13 years as of December 31, 2023.

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 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 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, 2023, and finance leases have remaining lease terms of approximately one month to six years as of December 31, 2023.

Lease expense consisted of the following for the years ended December 31, 2023, 2022 and 2021 (in thousands):


	Year Ended December 31,
	2023		2022		2021
Operating lease cost	$	10,073	$	5,664	$	4,984
Finance lease cost:
Amortization of right-of-use assets		6,360		—		—
Interest on lease liabilities		1,395		—		—
Total finance lease cost		7,755		—		—
Short-term lease expense (1)		2,278		—		41
Total lease expense (2)	$	20,106	$	5,664	$	5,025

(1)

Short-term lease expense represents expense related to leases with a contract term of one year or less.

(2)

Total lease expense is recorded in operating costs for the respective segments and within “selling, general and administrative” in our consolidated statements of operations.

F-33

Supplemental cash flow information related to leases for the years ended December 31, 2023, 2022 and 2021 is as follows (in thousands):


	Year Ended December 31,
	2023		2022		2021
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	8,935	$	6,858	$	7,323
Operating cash flows from finance leases		1,380		—		—
Financing cash flows from finance leases		15,915		—		—

Right of use assets obtained in exchange for lease obligations:
Operating leases (1)	$	34,802	$	6,530	$	6,413
Finance leases (1)		73,245		—		—

(1)

Includes right of use assets acquired in business combinations.

Supplemental balance sheet information related to leases as of December 31, 2023 and 2022 is as follows:


	December 31, 2023				December 31, 2022
Weighted Average Remaining Lease Term:
Operating leases	5.0 years			6.1 years
Finance leases	1.5 years				N/A

Weighted Average Discount Rate:
Operating leases		6.1	%			4.1	%
Finance leases		7.3	%		N/A

Maturities of operating and finance lease liabilities as of December 31, 2023 are as follows (in thousands):


Year ending December 31,	Operating			Finance
2024	$	16,435		$	46,297
2025		12,975			4,842
2026		9,387			4,850
2027		7,130			1,485
2028		4,975			1,485
Thereafter		9,354			2,080
Total lease payments		60,256			61,039
Less imputed interest		(8,867	)		(4,106	)
Total	$	51,389		$	56,933

14. Income Taxes

Income before income taxes for the United States for the year ended December 31, 2023 was $315 million. Income before income taxes for the United States for the year ended December 31, 2022 was $166 million. Loss before income taxes for the United States for the year ended December 31, 2021 was $721 million. Loss before income taxes for non-U.S. jurisdictions for the year ended December 31, 2023 was $8.8 million. Income before income taxes for non-U.S. jurisdictions for the years ended December 31, 2022 and 2021 was $2 million and $0.9 million, respectively.

Components of the income tax provision applicable to federal, state and foreign income taxes for the years ended December 31, 2023, 2022 and 2021 are as follows (in thousands):


	2023		2022			2021
Federal income tax expense (benefit):
Current	$	—	$	480		$	—
Deferred		44,369		11,820			(86,878	)
		44,369		12,300			(86,878	)
State income tax expense (benefit):
Current		7,002		2,647			144
Deferred		11,279		(4,896	)		23,028
		18,281		(2,249	)		23,172

F-34


Foreign income tax expense (benefit):
Current		1,578			2,750		134
Deferred		(3,076	)		403		870
		(1,498	)		3,153		1,004
Total income tax expense (benefit):
Current		8,580			5,877		278
Deferred		52,572			7,327		(62,980	)
Total income tax expense (benefit)	$	61,152		$	13,204	$	(62,702	)

The difference between the statutory U.S. federal income tax rate and the effective income tax rate for the years ended December 31, 2023, 2022 and 2021 is summarized as follows:


	2023			2022			2021
Statutory tax rate		21.0	%		21.0	%		21.0	%
State income taxes - net of the federal income tax benefit		3.2			3.0			3.0
State deferred tax remeasurement		(0.3	)		9.4			(0.8	)
Valuation allowance		(9.2	)		(33.4	)		(13.3	)
U.S. impact of foreign operations		—			1.3			—
Acquisition related costs		1.1			—			—
Effect of foreign taxes		0.1			1.6			(0.1	)
Non-deductible compensation		1.8			4.3			(0.3	)
Share-based compensation		1.6			(1.9	)		(0.3	)
Non-deductible expenses		0.7			1.2			(0.2	)
Other differences, net		(0.1	)		1.4			(0.3	)
Effective tax rate		19.9	%		7.9	%		8.7	%

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 tax effect of temporary differences and tax attributes representing deferred tax assets and liabilities at December 31, 2023 and 2022 are as follows (in thousands):


	2023			2022
Deferred tax assets:
Net operating loss carryforwards	$	498,948		$	382,936
Tax credits		13,488			4,222
Expense associated with stock options and restricted stock		10,892			8,178
Workers’ compensation allowance		7,024			15,770
Other deferred tax asset		69,480			25,020
		599,832			436,126
Less:
Allowance to reduce deferred tax asset to expected realizable value		(75,250	)		(91,685	)
Total deferred tax assets		524,582			344,441
Deferred tax liabilities:
Property and equipment basis difference		(729,376	)		(355,129	)
Other		(39,386	)		(14,840	)
Total deferred tax liabilities		(768,762	)		(369,969	)
Net deferred tax liability	$	(244,180	)	$	(25,528	)

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 2023, we reduced the valuation allowance against our net deferred tax assets by $16.4 million, which primarily related to U.S. federal and state activity.

F-35

For income tax purposes, we had approximately $1.9 billion of gross U.S. federal net operating losses, approximately $62.3 million of gross Canadian net operating losses, approximately $22.6 million of gross Colombian net operating losses and approximately $1.1 billion of post-apportionment U.S. state net operating losses as of December 31, 2023, before valuation allowances. The majority of U.S. federal net operating losses will expire in varying amounts, if unused, between 2030 and 2037. U.S. federal net operating losses generated after 2017 can be carried forward indefinitely. Canadian net operating losses will expire in varying amounts, if unused, between 2036 and 2043. Colombian net operating losses will expire in varying amounts, if unused, between 2028 and 2032. U.S. state net operating losses will expire in varying amounts, if unused, between 2024 and 2043.

As of December 31, 2023, 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, 2023, the tax years ended December 31, 2010 through December 31, 2022 are open for examination by U.S. taxing authorities. As of December 31, 2023, the tax years ended December 31, 2015 through December 31, 2022 are open for examination by Canadian taxing authorities. As of December 31, 2023, the tax years ended December 31, 2017 through December 31, 2022 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 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, 2023, 2022 and 2021, as well as potentially dilutive securities excluded from the weighted average number of diluted common shares outstanding because their inclusion would have been anti-dilutive (in thousands, except per share amounts):


	2023		2022		2021
BASIC EPS:
Net income (loss) from continuing operations attributed to common stockholders	$	246,292	$	154,658	$	(657,079	)
Net income from discontinued operations attributed to common stockholders	$	—	$	—	$	2,534
Net income (loss) attributed to common stockholders	$	246,292	$	154,658	$	(654,545	)
Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock		279,501		215,935		195,021
Basic income (loss) from continuing operations per common share	$	0.88	$	0.72	$	(3.37	)
Basic income from discontinued operations per common share	$	—	$	—	$	0.01
Basic net income (loss) per common share	$	0.88	$	0.72	$	(3.36	)

DILUTED EPS:
Net income (loss) from continuing operations attributed to common stockholders	$	246,292	$	154,658	$	(657,079	)
Net income from discontinued operations attributed to common stockholders	$	—	$	—	$	2,534
Net income (loss) attributed to common stockholders	$	246,292	$	154,658	$	(654,545	)
Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock		280,061		219,496		195,021
Diluted income (loss) from continuing operations per common share	$	0.88	$	0.70	$	(3.37	)
Diluted income from discontinued operations per common share	$	—	$	—	$	0.01
Diluted net income (loss) per common share	$	0.88	$	0.70	$	(3.36	)
Potentially dilutive securities excluded as anti-dilutive		9,214		3,541		9,551

F-36

We maintain a 401(k) plan for all eligible employees. Our operating results include expenses of approximately $18.7 million in 2023, $11.0 million in 2022 and $7.6 million in 2021 for our contributions to the plan.

17. Business Segments

Effective as of the third quarter of 2023, we revised our reportable segments to align with certain changes in how our CODM manages and allocates resources to our business as a result of the Ulterra acquisition and NexTier merger. Accordingly, we now have the following reportable business segments: (i) drilling services, (ii) completion services, and (iii) drilling products. As a result of the revised reportable segment structure, we have restated the corresponding items of segment information for all periods presented.

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.

Property and equipment, net and revenue for our domestic and international operations for the years ended December 31, 2023, 2022 and 2021 are as follows (in thousands):


	Year Ended December 31,
	2023		2022		2021
Property and equipment, net:
United States	$	3,257,937	$	2,213,242	$	2,292,448
Colombia		48,434		47,334		39,307
International (Excluding Colombia)		34,041		—		—
Property and equipment, net	$	3,340,412	$	2,260,576	$	2,331,755

Revenue:
United States	$	4,057,212	$	2,577,471	$	1,341,330
Colombia		50,692		70,121		15,751
International (Excluding Colombia)		38,552		—		—
Total revenues	$	4,146,456	$	2,647,592	$	1,357,081

Major Customer — During 2023, one customer accounted for approximately $588 million or 14% of our consolidated operating revenues. These revenues were earned in the drilling services, completion services, and drilling products 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. During 2021, one customer accounted for approximately $216 million or 16% 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):

F-37


	Year Ended December 31,
	2023			2022			2021
Revenues:
Drilling Services	$	1,976,401		$	1,581,380		$	805,295
Completion Services		2,017,440			1,022,413			523,756
Drilling Products		134,679			—			—
Other (1)		79,058			81,966			49,703
Elimination of intercompany revenues - Drilling Services (2)		(56,642	)		(36,560	)		(21,077	)
Elimination of intercompany revenues - Other (2)		(4,480	)		(1,607	)		(596	)
Total revenues	$	4,146,456		$	2,647,592		$	1,357,081

Segment operating income (loss) (3) and reconciliation to income (loss) before income taxes:
Drilling Services	$	422,002		$	149,807		$	(465,053	)
Completion Services		140,220			134,103			(118,863	)
Drilling Products		(6,501	)		—			—
Total segment operating income (loss) (3)		555,721			283,910			(583,916	)
Other		2,829			13,776			(3,182	)
Corporate		(205,754	)		(86,655	)		(92,152	)
Credit loss expense		(842	)		—			1,500
Interest income		6,122			360			222
Interest expense		(52,870	)		(40,256	)		(41,978	)
Other		1,898			(3,273	)		(275	)
Income (loss) before income taxes	$	307,104		$	167,862		$	(719,781	)

Depreciation, depletion, amortization and impairment:
Drilling Services	$	364,312		$	354,116		$	660,402
Completion Services		283,230			98,162			159,305
Drilling Products		48,467			—			—
Other		28,237			26,496			23,612
Corporate		7,170			5,171			5,859
Total depreciation, depletion, amortization and impairment	$	731,416		$	483,945		$	849,178

Capital expenditures:
Drilling Services	$	334,780		$	272,521		$	118,496
Completion Services		214,746			137,935			34,676
Drilling Products		24,572			—			—
Other		24,645			25,215			11,627
Corporate		16,947			1,126			1,521
Total capital expenditures	$	615,690		$	436,797		$	166,320

Identifiable assets:
Drilling Services	$	2,368,604		$	2,348,177		$	2,279,952
Completion Services		3,835,699			541,975			458,202
Drilling Products		1,011,870			—			—
Other		59,221			64,018			62,766
Corporate (4)		144,637			189,653			156,928
Total assets	$	7,420,031		$	3,143,823		$	2,957,848

(1)

Other includes our oilfield rentals business and oil and natural gas working interests.

(2)

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

(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 expenses and other operating income (loss).

(4)

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

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS


			Additions and adjustments
	Beginning		Charged to Costs			Charged to						Ending
Description	Balance		and Expenses			Other Accounts		Deductions				Balance
	(In thousands)
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
Year Ended December 31, 2021
Allowance for credit losses	$	10,842	$	(1,500	)	$	—	$	(849	)	(1)	$	8,493
Deferred tax valuation allowance		19,133		95,732			95,393		(20,521	)			189,737

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.

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 27, 2024.


10713 W. Sam Houston Pkwy N, Suite 800, Houston, Texas		77064
(Address of principal executive offices)		(Zip Code)


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


	1st		2nd		3rd		4th
	Quarter		Quarter		Quarter		Quarter
2021:
Average oil price per Bbl (1)	$	57.79	$	66.09	$	70.62	$	77.45
Average rigs operating per day – U.S. (2)		69		73		80		106
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


	Year Ended December 31,
	2023		2022		2021
Average rigs operating per day – U.S. (1)		124		124		82
Number of wells drilled during the year – U.S.		2,530		2,489		1,662
Number of operating days – U.S.		45,270		45,216		29,960


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 2023		58,178	$	12.87		—	$	281,031
November 2023		1,858,670	$	11.91		1,834,546	$	259,183
December 2023		5,121,552	$	11.07		4,825,639	$	205,676
Total		7,038,400				6,660,185


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


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


Large accelerated filer	☒	Accelerated filer	☐
		Smaller reporting company	☐
Non-accelerated filer	☐	Emerging growth company	☐


Region	Number of Rigs
West Texas		82
Appalachia		27
Rockies		23
Oklahoma		19
South Texas		18
East Texas		15
Colombia		8
Total		192


	Fiscal Year Ended December 31,
	2018		2019		2020		2021		2022		2023
Company/Index	($)		($)		($)		($)		($)		($)
Patterson-UTI Energy, Inc.		100.00		103.08		52.77		85.63		172.71		113.70
S&P 500 Index		100.00		131.47		155.65		200.29		163.98		207.04
S&P SmallCap 600 Index		100.00		122.74		136.53		173.04		145.10		168.23
Oilfield Service Index		100.00		99.45		57.60		69.55		112.31		114.47


	Year Ended December 31,
Drilling Services (1)	2023			2022			% Change
	(Dollars in thousands)
Revenues	$	1,919,759		$	1,544,820			24.3	%
Direct operating costs		1,119,200			1,025,904			9.1	%
Adjusted gross profit (2)		800,559			518,916			54.3	%
Selling, general and administrative		15,014			15,027			(0.1	)%
Depreciation, amortization and impairment		364,312			354,116			2.9	%
Other operating income, net		(769	)		(34	)		2,161.8	%
Operating income	$	422,002		$	149,807			181.7	%
Capital expenditures	$	334,780		$	272,521			22.8	%

Operating days – U.S. (3)		45,270			45,216			0.1	%
Average revenue per operating day – U.S.	$	36.24		$	27.57			31.5	%
Average direct operating costs per operating day – U.S.	$	19.42		$	17.32			12.1	%
Average adjusted gross profit per operating day – U.S. (3)	$	16.83		$	10.25			64.2	%


	Year Ended December 31,
Completion Services (1)	2023		2022		% Change
	(Dollars in thousands)
Revenues	$	2,017,440	$	1,022,413		97.3	%
Direct operating costs		1,567,940		781,385		100.7	%
Adjusted gross profit (2)		449,500		241,028		86.5	%
Selling, general and administrative		26,050		8,763		197.3	%
Depreciation, amortization and impairment		283,230		98,162		188.5	%
Operating income	$	140,220	$	134,103		4.6	%
Capital expenditures	$	214,746	$	137,935		55.7	%


	Per Share		Total
			(in thousands)
Paid on March 16, 2023	$	0.08	$	16,916
Paid on June 15, 2023		0.08		16,591
Paid on September 21, 2023		0.08		33,217
Paid on December 15, 2023		0.08		33,310
Total cash dividends	$	0.32	$	100,034


	Useful Lives	Change	Impact (in thousands)
Drilling services equipment	1-15 years	10%	$	47,423
Completion services equipment	1-25 years	10%		13,567
			$	60,990


	Drilling Services			Completion Services			Drilling Products			Other
	(in thousands)
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

For the year ended December 31, 2021
Revenues	$	784,218		$	523,756		$	—		$	49,107
Less direct operating costs		(577,983	)		(475,953	)		—			(28,012	)
Less depreciation, depletion, amortization and impairment		(660,402	)		(159,305	)		—			(23,612	)
GAAP gross profit		(454,167	)		(111,502	)		—			(2,517	)
Depreciation, depletion, amortization and impairment		660,402			159,305			—			23,612
Adjusted gross profit	$	206,235		$	47,803		$	—		$	21,095


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

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

2.3		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).

2.4		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).

2.5		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 September 1, 2023 as Exhibit 3.1 to our Current Report on Form 8-K 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.+

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).

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 June 8, 2023 (filed June 8, 2023 as Exhibit 99.1 to our Registration Statement on Form S-8 and incorporated herein by reference).*

10.3		Amendment to the Patterson-UTI Energy, Inc. 2021 Long-Term Incentive Plan, as amended (filed September 1, 2023 as Exhibit 10.5 to our Current Report on Form 8-K and incorporated herein by reference).*

10.4		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).*

10.5		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).*

10.6		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).*

10.7		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).*

10.8		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).*

10.9		Form of Non-Employee Director Restricted Stock Unit Award Agreement (filed May 3, 2022 as Exhibit 10.1 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 August 3, 2021 as Exhibit 10.3 to our Quarterly Report on Form 10-Q and incorporated herein by reference).*

10.11		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).*

10.12		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).*

10.13		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).*



10.14		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).*

10.15		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).*

10.16		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).*

10.17		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).*

10.18		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).*

10.19		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).*

10.20		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).*

10.21		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).*

10.22		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).*

10.23		Notice of Adjustment of NexTier Equity Awards in Connection with Merger, dated as of September 1, 2023.+*

10.24		Form of NexTier Oilfield Solutions Inc. RSU Award Agreement 2021 (filed February 24, 2021 as Exhibit 10.37 to NexTier Oilfield Solutions Inc.’s Annual Report on Form 10-K and incorporated herein by reference).*

10.25		Form of NexTier Oilfield Solutions Inc. RSU Award Agreement 2022 (filed February 23, 2022 as Exhibit 10.42 to NexTier Oilfield Solutions Inc.’s Annual Report on Form 10-K and incorporated herein by reference).*

10.26		Form of NexTier Oilfield Solutions Inc. RSU Award Agreement 2023 (filed February 16, 2023 as Exhibit 10.34 to NexTier Oilfield Solutions Inc.’s Annual Report on Form 10-K and incorporated herein by reference).*

10.27		Form of NexTier Oilfield Solutions Inc. PSU Award Agreement 2023 (filed February 16, 2023 as Exhibit 10.35 to NexTier Oilfield Solutions Inc.’s Annual Report on Form 10-K and incorporated herein by reference).*

10.28		Form of NexTier Oilfield Solutions Inc. Performance Award Agreement 2022 (filed February 23, 2022 as Exhibit 10.43 to NexTier Oilfield Solutions Inc.’s Annual Report on Form 10-K and incorporated herein by reference).*

10.29		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).*


10.30		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).

10.31		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).

10.32		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).

10.33		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).

10.34		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).

10.35		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).

10.36		Term Loan Agreement, dated August 29, 2023, by and among Patterson-UTI Energy, Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent and lender and the other lenders party thereto (filed September 1, 2023 as Exhibit 10.1 to our Current Report on Form 8-K and incorporated herein by reference).

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.+

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).


		Page
Report of Independent Registered Public Accounting Firm		F-2
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 2023 and 2022		F-5
Consolidated Statements of Operations for the years ended December 31, 2023, 2022 and 2021		F-6
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2023, 2022 and 2021		F-7
Consolidated Statements of Changes in Stockholders’ Equity for the years ended December 31, 2023, 2022 and 2021		F-8
Consolidated Statements of Cash Flows for the years ended December 31, 2023, 2022 and 2021		F-9
Notes to Consolidated Financial Statements		F-10


	December 31,
	2023			2022
	(In thousands, except share data)
ASSETS
Current assets:
Cash, cash equivalents and restricted cash	$	192,680		$	137,553
Accounts receivable, net of allowance for credit losses of $3,490 and $2,875 at December 31, 2023 and 2022, respectively		971,091			565,520
Inventory		180,805			65,377
Other current assets		141,122			60,969
Total current assets		1,485,698			829,419
Property and equipment, net		3,340,412			2,260,576
Operating lease right of use asset		47,599			20,841
Finance lease right of use asset		63,228			—
Goodwill		1,379,741			—
Intangible assets, net		1,051,697			5,845
Deposits on equipment purchases		28,305			13,051
Other assets		19,424			10,881
Deferred tax assets, net		3,927			3,210
Total assets	$	7,420,031		$	3,143,823

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	534,420		$	237,056
Accrued liabilities		446,268			308,787
Operating lease liability		13,541			5,123
Finance lease liability		43,980			—
Current maturities of long-term debt		12,226			—
Total current liabilities		1,050,435			550,966
Long-term operating lease liability		37,848			19,594
Long-term finance lease liability		12,953			—
Long-term debt, net of debt discount and issuance costs of $8,919 and $5,468 at December 31, 2023 and 2022, respectively		1,224,941			830,937
Deferred tax liabilities, net		248,107			28,738
Other liabilities		25,066			48,065
Total liabilities		2,599,350			1,478,300
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 400,000,000 shares with 516,775,313 and 302,325,853 issued and 411,195,302 and 213,567,131 outstanding at December 31, 2023 and 2022, respectively		5,166			3,023
Additional paid-in capital		6,407,294			3,202,973
Retained earnings (deficit)		57,035			(87,394	)
Accumulated other comprehensive income		472			—
Treasury stock, at cost, 105,580,011 shares and 88,758,722 shares at December 31, 2023 and 2022, respectively		(1,657,675	)		(1,453,079	)
Total stockholders’ equity attributable to controlling interests		4,812,292			1,665,523
Noncontrolling interest		8,389			—
Total equity		4,820,681			1,665,523
Total liabilities and stockholders’ equity	$	7,420,031		$	3,143,823


											Accumulated
	Common Stock				Additional			Retained			Other
	Number of				Paid-in			Earnings			Comprehensive			Treasury			Noncontrolling
	Shares		Amount		Capital			(Deficit)			Income			Stock			Interest			Total
	(In thousands)
Balance, December 31, 2020		271,029	$	2,710	$	2,902,236		$	472,014		$	5,412		$	(1,366,313	)		—		$	2,016,059
Net loss		—		—		—			(654,545	)		—			—			—			(654,545	)
Foreign currency translation adjustment		—		—		—			—			503			—			—			503
Shares issued for acquisition		26,274		263		247,762			—			—			—			—			248,025
Issuance of restricted stock		621		6		(6	)		—			—			—			—			—
Vesting of restricted stock units		1,345		14		(14	)		—			—			—			—			—
Stock-based compensation		—		—		21,558			—			—			—			—			21,558
Payment of cash dividends ($0.08 per share)		—		—		—			(15,605	)		—			—			—			(15,605	)
Dividend equivalents		—		—		—			(180	)		—			—			—			(180	)
Purchase of treasury stock		—		—		—			—			—			(6,328	)		—			(6,328	)
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 (loss)		—		—		—			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


	2023		2022
Raw materials and supplies	$	141,311	$	63,008
Work-in-process		7,437		2,341
Finished goods		32,057		28
Inventory	$	180,805	$	65,377


	2023		2022
Federal and state income taxes receivable	$	26,949	$	11,313
Workers’ compensation receivable		31,006		34,632
Prepaid expenses		46,394		11,960
Other		36,773		3,064
Other current assets	$	141,122	$	60,969


	2023		2022
Salaries, wages, payroll taxes and benefits	$	129,982	$	73,308
Workers’ compensation liability		67,396		67,853
Property, sales, use and other taxes		62,194		10,119
Insurance, other than workers’ compensation		11,524		3,644
Accrued interest payable		19,172		10,522
Deferred revenue		98,914		110,215
Federal and state income taxes payable		3,437		4,644
Accrued merger and integration expense		15,113		—
Other		38,536		28,482
Accrued liabilities	$	446,268	$	308,787


	December 31, 2023				December 31, 2022
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
3.95% Senior Notes Due 2028	$	482,505	$	450,540	$	488,505	$	431,556
5.15% Senior Notes Due 2029		344,895		329,032		347,900		313,164
7.15% Senior Notes Due 2033		400,000		424,946		—		—
Equipment Loans Due 2025		18,686		18,766		—		—
Total debt	$	1,246,086	$	1,223,284	$	836,405	$	744,720


PATTERSON-UTI ENERGY, INC.

By:		/s/ William Andrew Hendricks, Jr.
		William Andrew Hendricks, Jr.
		President and Chief Executive Officer


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