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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

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

For the fiscal year ended December 31, 2021

or

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

For the transition period from to

Commission File Number 1-39270

Patterson-UTI Energy, Inc.

(Exact name of registrant as specified in its charter)

Delaware |  |  | 75-2504748
(State or other jurisdiction of incorporation or organization) |  |  | (I.R.S. Employer Identification No.)

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

Registrant’s telephone number, including area code:

(281) 765-7100

Securities registered pursuant to Section 12(b) of the Act:

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

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ 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.

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

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

Indicate by check mark whether the registrant 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. ☒

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, 2021, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $1.8 billion, calculated by reference to the closing price of $9.94 for the common stock on the Nasdaq Global Select Market on that date.

As of February 10, 2022, the registrant had outstanding 215,265,785 shares of common stock, $0.01 par value, its only class of common stock.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement for the 2022 Annual Meeting of Stockholders are incorporated by reference into Part III of this report.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K (this “Report”) and other public filings, press releases and presentations by us contain “forward-looking statements” within the meaning of the Securities Act of 1933, as amended (the “Securities Act”), the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the Private Securities Litigation Reform Act of 1995, as amended. As used in this Report, “we,” “us,” “our,” “ours” and like terms refer collectively to Patterson-UTI Energy, Inc. and its consolidated subsidiaries. Patterson-UTI Energy, Inc. conducts its operations through its wholly-owned subsidiaries and has no employees or independent business operations. These forward-looking statements involve risk and uncertainty. These forward-looking statements include, without limitation, statements relating to: liquidity; revenue, cost and margin expectations and backlog; financing of operations; oil and natural gas prices; rig counts and frac spreads; source and sufficiency of funds required for building new equipment, upgrading existing equipment and acquisitions (if opportunities arise); demand and pricing for our services; competition; equipment availability; government regulation; legal proceedings; debt service obligations; impact of inflation; and 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:

•
adverse oil and natural gas industry conditions, including as a result of economic repercussions from the COVID-19 pandemic;
•
global economic conditions;
•
volatility in customer spending and in oil and natural gas prices that could adversely affect demand for our services and their associated effect on rates;
•
excess availability of land drilling rigs, pressure pumping and directional drilling equipment, including as a result of reactivation, improvement or construction;
•
competition and demand for our services;
•
strength and financial resources of competitors;
•
utilization, margins and planned capital expenditures;
•
liabilities from operational risks for which we do not have and receive full indemnification or insurance;
•
operating hazards attendant to the oil and natural gas business;
•
failure by customers to pay or satisfy their contractual obligations (particularly with respect to fixed-term contracts);
•
the ability to realize backlog;
•
specialization of methods, equipment and services and new technologies, including the ability to develop and obtain satisfactory returns from new technology;
•
the ability to retain management and field personnel;
•
loss of key customers;
•
shortages, delays in delivery, and interruptions in supply, of equipment and materials;
•
cybersecurity events;
•
synergies, costs and financial and operating impacts of acquisitions;
•
the effects of the acquisition of Pioneer Energy Services Corp. (“Pioneer”) on us, including our future financial condition, results of operations, strategy and plans;

1

•
potential adverse reactions or changes to business or employee relationships resulting from the acquisition;
•
the failure to realize expected synergies and other benefits from the acquisition in the timeframe expected or at all;
•
difficulty in building and deploying new equipment;
•
governmental regulation;
•
climate legislation, regulation and other related risks;
•
environmental, social and governance practices, including the perception thereof;
•
environmental risks and ability to satisfy future environmental costs;
•
technology-related disputes;
•
legal proceedings and actions by governmental or other regulatory agencies;
•
the ability to effectively identify and enter new markets;
•
weather;
•
operating costs;
•
expansion and development trends of the oil and natural gas industry;
•
ability to obtain insurance coverage on commercially reasonable terms;
•
financial flexibility;
•
adverse credit and equity market conditions;
•
availability of capital and the ability to repay indebtedness when due;
•
stock price volatility;
•
compliance with covenants under our debt agreements; and
•
other financial, operational and legal risks and uncertainties detailed from time to time in our filings with the SEC.

We caution that the foregoing list of factors is not exhaustive. Additional information concerning these and other risk factors is contained in this Report and may be contained in our future filings with the SEC. You are cautioned not to place undue reliance on any of our forward-looking statements. The forward-looking statements speak only as of the date made and, other than as required by law, we undertake no obligation to update publicly or revise any of these forward-looking statements, whether as a result of new information, future events or otherwise. In the event that we update any forward-looking statement, no inference should be made that we will make additional updates with respect to that statement, related matters or any other forward-looking statements. All subsequent written and oral forward-looking statements concerning us or other matters and attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements above.

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PART I

Item 1. Business

Available Information

This Report, along with our Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, are available free of charge through our internet website (www.patenergy.com) as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. The information contained on our website is not part of this Report or other filings that we make with the SEC. The SEC maintains an internet site (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.

Overview

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

Our contract drilling business operates in the continental United States and internationally in Colombia and, from time to time, we pursue contract drilling opportunities in other select markets. As of December 31, 2021, we had a drilling fleet that consisted of 184 marketed land-based drilling rigs in the United States and eight in Colombia. A drilling rig includes the structure, power source and machinery necessary to cause a drill bit to penetrate the earth to a depth desired by the customer. We also have a substantial inventory of drill pipe and drilling rig components that support our contract drilling operations.

We provide pressure pumping services to oil and natural gas operators primarily in Texas and the Appalachian region. Substantially all of the revenue in the pressure pumping segment is from well stimulation services (such as hydraulic fracturing) for completion of new wells and remedial work on existing wells. Well stimulation involves processes inside a well designed to enhance the flow of oil, natural gas, or other desired substances from the well. As of December 31, 2021, we had approximately 1.1 million fracturing horsepower to provide these services. We also provide cementing services through the pressure pumping segment. Cementing is the process of inserting material between the wall of the well bore and the casing to support and stabilize the casing. Our pressure pumping operations are supported by a fleet of other equipment, including blenders, tractors, manifold trailers and numerous trailers for transportation of materials to and from the worksite as well as bins for storage of materials at the worksite.

We also provide a comprehensive suite of directional drilling services in most major producing onshore oil and gas basins in the United States. Our directional drilling services include directional drilling, measurement-while-drilling and supply and rental of downhole performance motors. We also provide services that improve the statistical accuracy of directional and horizontal wellbores.

We have other operations through which we provide oilfield rental tools in select markets in the United States. We also service equipment for drilling contractors, and we provide electrical controls and automation to the energy, marine and mining industries in North America and other select markets. In addition, we own and invest, as a non-operating working interest owner, in oil and natural gas assets that are primarily located in Texas and New Mexico.

Recent Developments

Recent Developments in Market Conditions — Quarterly average oil prices and our quarterly average number of rigs operating in the United States for 2019, 2020 and 2021 are as follows:

|  | 1 st |  |  | 2 nd |  |  | 3 rd |  |  | 4 th |
|  | Quarter |  |  | Quarter |  |  | Quarter |  |  | Quarter |
2019: |  |  |  |  |  |  |  |  |  |  |  |
Average oil price per Bbl (1) |  | $ | 54.83 |  |  | $ | 59.78 |  |  | $ | 56.37 |  |  | $ | 56.94 |
Average rigs operating per day - U.S. (2) |  |  | 174 |  |  |  | 157 |  |  |  | 142 |  |  |  | 122 |
2020: |  |  |  |  |  |  |  |  |  |  |  |
Average oil price per Bbl (1) |  | $ | 45.76 |  |  | $ | 27.81 |  |  | $ | 40.89 |  |  | $ | 42.45 |
Average rigs operating per day - U.S. (2) |  |  | 123 |  |  |  | 82 |  |  |  | 60 |  |  |  | 62 |
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 |

3

(1)
The average oil price represents the average monthly West Texas Intermediate (WTI) spot price as reported by the United States Energy Information Administration.
(2)
A rig is considered to be operating if it is earning revenue pursuant to a contract on a given day.

In 2020, reduced demand for crude oil and refined products related to the COVID-19 pandemic led to a significant reduction in crude oil prices and demand for drilling and completion services in the United States.

Oil prices remain extremely volatile, as the closing price of oil (WTI-Cushing) reached a first quarter 2020 high of $63.27 per barrel on January 6, 2020, declined to negative $36.98 per barrel on April 20, 2020, and recovered to reach a 2021 high of $85.64 per barrel on October 26, 2021. In response to the rapid decline in commodity prices, E&P companies acted swiftly to reduce drilling and completion activity starting late in the first quarter of 2020. While oil prices have recovered in 2021, and demand for our services has improved since the commodity price decline in 2020, our average number of rigs operating remains well below the number of our available rigs, and a portion of our pressure pumping horsepower remains stacked. Oil prices averaged $77.45 per barrel in the fourth quarter of 2021.

Although our active rig count has not fully recovered to its 2019 levels, it increased in 2021 after significant declines in 2020. Our average active U.S. rig count for the fourth quarter of 2021 was 106 rigs. This was an increase from our average active rig count for the third quarter of 2021 of 80 rigs. The increase was partially due to our acquisition of active U.S. rigs from Pioneer Energy Services Corp. (“Pioneer”), which averaged 13 active rigs during the fourth quarter of 2021. Our active U.S. rig count at December 31, 2021 of 111 rigs was more than the rig count of 65 rigs at December 31, 2020, partially due to the increase in rigs from the Pioneer acquisition and, more significantly, due to the recovery of oil prices and improved demand for drilling services in the United States. Term contracts help support our operating rig count. Based on contracts currently in place in the United States, we expect an average of 51 rigs operating under term contracts during the first quarter, and an average of 39 rigs operating under term contracts during 2022.

We ended the fourth quarter of 2021 with 11 active pressure pumping spreads compared to ten at the end of the third quarter. Our average active spread count was approximately ten spreads and effective utilization was close to 11 spreads for the fourth quarter of 2021. We calculated average active spreads as the average number of spreads that were crewed and actively marketed during the period, and we calculated effective utilization as total pumping days during the quarter divided by 75 days, which we consider full effective utilization for a spread for the period. We expect to average approximately 11 active spreads in the first quarter of 2022. The pressure pumping market has improved but remains oversupplied.

Due to improving activity levels and increasing tightness in the overall labor market, we saw general oilfield cost inflation across our segments during 2021, including increases in the cost of labor, services and supplies. This inflation, combined with the increasing challenge of attracting employees to the industry, is increasing the complexity of reactivating equipment. We believe this challenge, combined with the increasing market tightness for premium drilling and completion services, will support higher pricing for our services in 2022. During 2021, we increased our capital expenditure forecast to approximately $170 million, in part, based on conversations with customers about increasing activity levels into 2022. Actual 2021 capital expenditures excluding discontinued operations totaled $166 million.

During the second quarter of 2020, we implemented a restructuring plan to improve operating margins, achieve operational efficiencies and reduce indirect support costs. The restructuring included workforce reductions, changes to management structure and facility consolidations and closures.

Recent Developments in Financial Matters and Merger and Acquisition Activity — On October 1, 2021, we completed the acquisition of Pioneer Energy Services Corp. (“Pioneer”) by acquiring 100% of its equity interests. Total consideration for the acquisition included the issuance of approximately 26.3 million shares of our common stock and payment of $30 million cash, which based on the closing price of our common stock of $9.44 on October 1, 2021, valued the transaction at approximately $278 million.

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

4

On December 31, 2021, we completed the sale of the acquired well servicing rig business and wireline business (collectively, “Pioneer Production Services”), to Clearwell Dynamics, LLC (“Clearwell”). The sale price was $43.0 million in cash consideration, subject to customary purchase price adjustments at closing for cash and working capital. The results of operations of these businesses have been presented as a discontinued operation in these consolidated financial statements. In connection with the sale of our Pioneer Production Services business, we entered into a transition services agreement with Clearwell, pursuant to which we agreed to provide each other certain administrative and operational services on an interim, transitional basis through June 30, 2022.

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

Industry Segments

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

•
contract drilling services,
•
pressure pumping services, and
•
directional drilling services.

Our contract drilling services, pressure pumping services, and directional drilling services industry segments had operating losses in 2021, 2020 and 2019.

See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 17 of Notes to Consolidated Financial Statements included as a part of Items 7 and 8, respectively, of this Report for financial information pertaining to these industry segments.

Contract Drilling Operations

General — We market our contract drilling services to oil and natural gas operators in the United States and Colombia. As of December 31, 2021, we had 192 marketed land-based drilling rigs based in the following regions:

Region |  | Number of Rigs |
West Texas |  |  | 73 |
Appalachia |  |  | 33 |
Rockies |  |  | 24 |
Oklahoma |  |  | 20 |
South Texas |  |  | 19 |
East Texas |  |  | 15 |
Colombia |  |  | 8 |
Total |  |  | 192 |

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. We have 171 super-spec rigs in total.

Due to evolving customer preferences, we have begun to refer to certain premium rigs as “Tier-1, super-spec” rigs, which we consider as being a super-spec rig that also has a third mud pump and raised drawworks that allow for more clearance underneath the rig floor. We currently estimate there are fewer than 400 Tier-1, super-spec rigs in the United States, which includes our 107 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.

5

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. To address our customers’ needs for drilling horizontal wells in shale and other unconventional resource plays, we have improved the capability of our drilling fleet during the last several years. 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. We have spent approximately $409 million during the last three years on capital expenditures to modify, upgrade and extend the lives of components of our drilling fleet. During fiscal years 2021, 2020 and 2019, we spent approximately $110 million, $105 million and $194 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:

|  | Year Ended December 31, |
|  | 2021 |  |  | 2020 |  |  | 2019 |
Average rigs operating per day - U.S. (1) |  |  | 82 |  |  |  | 82 |  |  |  | 149 |
Number of rigs operated during the year - U.S. |  |  | 118 |  |  |  | 131 |  |  |  | 186 |
Number of wells drilled during the year - U.S. |  |  | 1,662 |  |  |  | 1,324 |  |  |  | 2,690 |
Number of operating days - U.S. |  |  | 29,960 |  |  |  | 29,857 |  |  |  | 54,282 |

(1)
A rig is considered to be operating if it is earning revenue pursuant to a contract on a given day.

Rig Fleet Evaluation — On a periodic basis, we evaluate our fleet of drilling rigs for marketability based on the condition of inactive rigs, expenditures that would be necessary to bring inactive rigs to working condition and the expected demand for drilling services by rig type. The components comprising rigs that will no longer be marketed are evaluated, and those components with continuing utility to our other marketed rigs are transferred to other rigs or to our yards to be used as spare equipment. The remaining components of these rigs are retired. 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.

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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.

Pressure Pumping Operations

General — We provide pressure pumping services to oil and natural gas operators, primarily in Texas and the Appalachian region (Northeast Region). Pressure pumping services consist primarily of well stimulation services (such as hydraulic fracturing) for the completion of new wells and remedial work on existing wells. Wells drilled in shale formations and other unconventional plays require well stimulation through hydraulic fracturing to allow the flow of oil and natural gas. This is accomplished by pumping fluids and proppant under pressure into the well bore to fracture the formation. Many wells in conventional plays also receive well stimulation services. We also provide cementing services through the pressure pumping segment. The cementing process inserts material between the wall of the well bore and the casing to support and stabilize the casing. The scope and impact of our cementing services were insignificant during the fiscal years 2021, 2020 and 2019.

Pressure Pumping Contracts — Our pressure pumping operations are conducted pursuant to a work order for a specific job or pursuant to a term contract. The term contracts are generally entered into for a specified period of time and 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 pressure pumping equipment used in providing hydraulic fracturing services as well as cementing and acid pumping services, with a total of approximately 1.1 million horsepower as of December 31, 2021. Pressure pumping equipment at December 31, 2021 included:

|  |  |  |  | Other |  |  |  |
|  | Fracturing |  |  | Pumping |  |  |  |
|  | Equipment |  |  | Equipment |  |  | Total |
Texas Region |  |  |  |  |  |  |  |  |
Number of units |  |  | 355 |  |  |  | 12 |  |  |  | 367 |
Approximate horsepower |  |  | 847,500 |  |  |  | 14,280 |  |  |  | 861,780 |
Northeast Region |  |  |  |  |  |  |  |  |
Number of units |  |  | 121 |  |  |  | 9 |  |  |  | 130 |
Approximate horsepower |  |  | 281,900 |  |  |  | 5,800 |  |  |  | 287,700 |
Combined: |  |  |  |  |  |  |  |  |
Number of units |  |  | 476 |  |  |  | 21 |  |  |  | 497 |
Approximate horsepower |  |  | 1,129,400 |  |  |  | 20,080 |  |  |  | 1,149,480 |

Our pressure pumping operations are supported by a fleet of other equipment including blenders, tractors, manifold trailers and numerous trailers for transportation of materials to and from the worksite, as well as bins for storage of materials at the worksite.

We periodically evaluate our pressure pumping 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. 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 pressure pumping 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.

Materials — Our pressure pumping 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. 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.

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Directional Drilling Operations

General — 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. We believe our customers use our services because of the quality of our specialized, technology-driven equipment and our well-trained and experienced workforce, which enable us to provide our customers with high-quality, reliable and safe directional drilling services.

Directional Drilling Services — We provide our directional drilling services primarily on a dayrate basis, typically under master service agreements. Revenue from directional drilling services is recognized as work progresses based on the number of days or footage completed. Our rates and other charges generally vary by location and depend on the equipment and personnel required for the job and market conditions in the region in which the services are performed. In addition to rates that are charged during periods of active directional drilling, a standby rate is typically agreed upon in advance and charged on a daily basis during periods when drilling is temporarily suspended while other on-site activity is conducted at the direction of the operator or another service provider.

Equipment — We generally design, assemble, maintain and inspect our own equipment. We have developed proprietary equipment for our drilling motors, mud pulse and electromagnetic data transfer MWD equipment. We believe that our vertical integration strategy allows us to deliver better operational performance and higher equipment reliability to our customers. Vertical integration also allows us to build our tools more efficiently and at a lower cost than if purchased from third parties. In addition, we have the ability to upgrade our tools in response to market conditions or our customers’ job requirements, which allows us to minimize the costs and delays associated with sending equipment to original manufacturers. Our internal maintenance capability also affords us enhanced control over our supply chain and increases the effective utilization of our assets.

We periodically evaluate our directional drilling 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. The inventory write-down in 2021 totaled $4.0 million.

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 measurement-while-drilling (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 recommendation 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 Operations

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 onshore oil and gas basins in the United States. We service equipment for drilling contractors, and we provide electrical controls and automation to the energy, marine and mining industries in North America and other select markets. In addition, we own and invest, as a non-operating working interest owner, in oil and natural gas assets that are primarily located in Texas and New Mexico.

Contracts

We believe that our contract drilling, pressure pumping, directional drilling and other contracts generally provide for indemnification rights and obligations that are customary for the markets in which we conduct those operations. However, each contract contains the actual terms setting forth our rights and obligations and those of the customer or supplier, any of which rights and obligations may deviate from what is customary due to particular industry conditions, customer or supplier requirements, applicable law or other factors.

Customers

Our customer base includes major, independent and other oil and natural gas operators. With respect to our consolidated operating revenues in 2021, we received approximately 57% from our ten largest customers and approximately 39% from our five largest customers. During 2021, one customer accounted for approximately $216 million, or approximately 16%, of our consolidated operating revenues. These revenues were earned in both our contract drilling and pressure pumping businesses. 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.

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Backlog

Our contract drilling backlog in the United States as of December 31, 2021 and 2020 was approximately $325 million and $301 million, respectively. Approximately 22% of our contract drilling backlog in the United States at December 31, 2021 is reasonably expected to remain after 2022. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included as a part of Item 7 of this Report for information pertaining to backlog.

Competition

The businesses in which we operate are highly competitive. Historically, available equipment used in our contract drilling, pressure pumping and directional drilling businesses has frequently exceeded demand, particularly in an industry downturn. The price for our services is a key competitive factor, in part because equipment used in these businesses can be moved from one area to another in response to market conditions. In addition to price, we believe availability, condition and technical specifications of equipment (including emission reduction capabilities), quality of personnel, service quality and safety record are key factors in determining which contractor is awarded a job. We expect that the market for our services will continue to be highly competitive.

Human Capital and Sustainability

We strive to be a leader in our industry in the area of environmental, social, governance and other sustainability-related issues, and we remain committed to managing these issues for the long-term benefit of our employees, 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 are our most important asset and our greatest strength. Importantly, we maintain a rigorous focus on ethics and integrity at every level of our operations, a practice on which all of our success depends.

We encourage you to review our latest Sustainability Report, located on our website, for more detailed information regarding our Sustainability and Human Capital programs and initiatives. Nothing on our website, including our Sustainability Report or sections thereof, shall be deemed incorporated by reference into this Report or other filings that we make with the SEC.

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, 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. EcoCell™ 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.

Some of our key human capital areas of focus include:

Employees – We had approximately 5,000 full-time employees as of January 31, 2022. 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 in place 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 safety education on an annual basis which incorporates learning associated with hazard awareness, safe systems of work, permission to work, time out for safety, energy isolation, material handling and management of change.

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In response to the COVID-19 pandemic, we implemented, and continue to maintain, safety protocols at our offices, facilities and worksites. These protocols include allowing many of our office-based employees to work from home.

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 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 – In 2021, we trained over 3,500 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.

Government and Environmental Regulation

All of 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, including:

•
drilling of oil and natural gas wells,
•
hydraulic fracturing, cementing and acidizing and related well servicing activities,
•
directional drilling services,
•
services that improve the accuracy of directional and horizontal wellbores, including for customers with offshore operations, wellbore quality, and on-bottom ROP,
•
containment and disposal of hazardous materials, oilfield waste, other waste materials and acids,
•
use of underground storage tanks and injection wells,
•
servicing of equipment for drilling contractors,
•
provision of electrical controls and automation, and
•
our employees.

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.

Our business is generally affected by political developments and by federal, state, foreign, regional and local laws, rules and regulations that relate to the oil and natural gas industry. 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 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. Federal, state, foreign, regional and local environmental laws, rules and regulations, including laws, rules, regulations and executive actions related to the mitigation of climate change or greenhouse gas emissions, currently apply to our operations and are likely to become more stringent in the future. Any limitation, suspension or moratorium of the services and products we or others provide, whether or not short-term in nature, by a federal, state, foreign, regional or local governmental authority, could have a material adverse effect on our business, financial condition and results of operations.

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We believe we use operating and disposal practices that are standard in the industry. However, 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.

Some of the environmental laws and regulations that are applicable to our business operations are discussed in the following paragraphs, but the discussion does not cover all environmental laws and regulations that may govern our operations.

In the United States, the Federal Comprehensive Environmental Response Compensation and Liability Act of 1980, as amended, commonly known as 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; and
•
persons who disposed of or arranged for the disposal of “hazardous substances” found at sites.

The Federal 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. For example, in December 2016, the U.S. Environmental Protection Agency (“EPA”) and environmental groups entered into a consent decree to address the EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and gas wastes from regulation as hazardous wastes under RCRA. The consent decree requires the EPA to propose a rulemaking by March 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. The EPA issued a report on April 23, 2019, determining that no revisions were necessary. However, if changes are made to the classification of exploration and production wastes under CERCLA and/or RCRA in the future, we could be required to remove and remediate previously disposed of materials (including materials disposed of or released by prior owners or operators) from properties (including ground water contaminated with hydrocarbons) and to perform removal or remedial actions to prevent future contamination.

The Federal Water Pollution Control Act (the “Clean Water Act”) and the Oil Pollution Act of 1990 (the “Oil Pollution Act”), each as amended, and implementing regulations govern:

•
the prevention and permitting of discharges, including oil and produced water spills, into jurisdictional waters; and
•
liability for drainage into such waters.

The Oil Pollution Act imposes strict liability for a comprehensive and expansive list of damages from an oil spill into jurisdictional waters from facilities. Liability may be imposed for oil removal costs and a variety of public and private damages. Penalties may also be imposed for violation of federal safety, construction and operating regulations, and for failure to report a spill or to cooperate fully in a clean-up.

The Oil Pollution Act also expands the authority and capability of the federal government to direct and manage oil spill clean-up and operations, and requires operators to prepare oil spill response plans in cases where it can reasonably be expected that substantial harm will be done to the environment by discharges on or into navigable waters. Failure to comply with ongoing requirements or inadequate cooperation during a spill event may subject a responsible party, such as us, to civil or criminal actions. Although the liability for owners and operators is the same under the Clean Water Act, the damages recoverable under the Oil Pollution Act are potentially much greater and can include natural resource damages.

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.

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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. Due to concerns raised relating to potential impacts of hydraulic fracturing, including on groundwater quality and seismic activity, legislative and regulatory efforts at the federal level and in some state and local jurisdictions have been initiated to render permitting and compliance requirements more stringent for hydraulic fracturing or prohibit the activity altogether. Certain politicians have also vocalized support for a nationwide ban on hydraulic fracturing. Additional legislation or regulation could lead to operational delays or increased operating costs in the production of oil and natural gas or could make it more difficult to perform hydraulic fracturing. These developments could also lead to litigation challenging proposed or existing wells. Such efforts could have an adverse effect on oil and natural gas production activities, which in turn could have an adverse effect on the hydraulic fracturing services that we provide for our exploration and production customers, and such efforts could adversely affect our business, financial condition, cash flows and results of operations. See “Item 1A. Risk Factors – Potential Legislation and Regulation Covering Hydraulic Fracturing or Other Aspects of the Oil and Gas Industry Could Increase Our Costs and Limit or Delay Our Operations.”

Other jurisdictions where we may conduct operations have similar environmental and 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.

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 Federal 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.

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.”

There has been an increasing focus of local, state, national and international regulatory bodies on greenhouse gas (“GHG”) emissions and climate change issues. There has also been legislation proposed by U.S. lawmakers to reduce GHG emissions, as well as GHG emissions regulations enacted by the EPA, and future federal action to address climate change is likely.

President Biden and the Democratic Party, which controls Congress, have identified climate change as a priority, and it is likely that additional executive orders, regulatory action, and/or legislation targeting greenhouse gas emissions, or prohibiting, delaying or restricting oil and gas development activities in certain areas, will be proposed and/or promulgated during the Biden Administration. For example, the acting Secretary of the Department of the Interior recently issued an order preventing staff from producing any new fossil fuel leases or permits without sign-off from a top political appointee, and President Biden recently announced a moratorium on new oil and gas leasing on federal lands and offshore waters pending completion of a comprehensive review and reconsideration of Federal oil and 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 nationwide preliminary injunction against the pause of oil and natural gas leasing on public lands or in offshore waters while litigation challenging that aspect of the executive order is ongoing, the Biden Administration may take other regulatory steps in the future that could impact our operations.

In February 2021, the United States rejoined the Paris Agreement, and in the future, the United States may also choose to adhere to other international agreements targeting GHG reductions. In April 2021, President Biden set a new goal for the United States to achieve a 50-52 percent reduction from 2005 levels in economy-wide net greenhouse gas pollution in 2030. Further, in November 2021, the Unites 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 by 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.

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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. 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.”

Risks and Insurance

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, 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. 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.

We maintain insurance coverage of types and amounts that we believe to be customary in the industry, but we are not fully insured against all risks, either because insurance is not available or because of the high premium costs. The insurance coverage that we maintain includes insurance 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 and insurance for other specific risks. We cannot assure, however, that any insurance obtained by us will be adequate to cover any losses or liabilities, or that this insurance will continue to be available, or available on terms that are acceptable to us. 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 accept 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, a $2.0 million per occurrence deductible on our primary automobile liability insurance coverage, and a $5.0 million per occurrence deductible on our excess automobile liability insurance coverage. We also self-insure a number of other 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.

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.

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

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.

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Raw Materials and Subcontractors

We use many suppliers of raw materials and services. Although these materials and services have historically been available, there is no assurance that such materials and services will continue to be available on favorable terms or at all. We also utilize numerous independent subcontractors from various trades.

Item 1A. Risk Factors.

You should consider each of the following factors as well as the other information in this Report in evaluating our business and our prospects. Additional risks and uncertainties not presently known to us or that we currently consider immaterial may also impair our business operations. If any of the following risks actually occur, our business, financial condition, cash flows and results of operations could be harmed. You should also refer to the other information set forth in this Report, including our consolidated financial statements and the related notes.

Business and Operating Risks

The Effects of the COVID-19 Pandemic, Have Had, and Are Expected to Continue to Have, a Significant Adverse Impact on Our Business, Liquidity, Results of Operations and Financial Condition.

The effects of the COVID-19 pandemic, including related governmental actions and restrictions, have had, and are expected to continue to 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, which has impacted and is expected to continue to impact our business, liquidity, results of operations and our financial condition.

In response to the COVID-19 pandemic, governmental authorities have imposed mandatory closures, sought voluntary closures and imposed restrictions on, or advisories with respect to, travel, business operations and public gatherings or interactions. While many governmental authorities have loosened these restrictions, the ongoing COVID-19 outbreak may significantly worsen, and new strains of COVID-19 may emerge, which may cause governmental authorities to reconsider restrictions on travel, business and social activities. In the event governmental authorities retain, increase or reimpose restrictions, the loosening of restrictions may be further curtailed.

In early March 2020, OPEC+ was initially unable to reach an agreement to continue to impose limits on the production of crude oil, and shortly thereafter the World Health Organization determined the COVID-19 outbreak to be a pandemic. The convergence of these events created the unprecedented dual impact of a global oil demand decline coupled with the risk of a substantial increase in supply. In response to the rapid decline in commodity prices, exploration and production companies acted swiftly to reduce drilling and completion activity starting late in the first quarter of 2020. While oil prices and demand for our services have recovered in 2021, customer spending has not returned to pre-pandemic levels.

Given the nature and significance of the events described above, we are not able to enumerate all potential risks to our business from the recent volatility in crude oil prices and the COVID-19 pandemic; however, we believe that in addition to the impacts described above, other current and potential impacts of these recent events include, but are not limited to:

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liquidity challenges, including impacts related to delayed customer payments and payment defaults associated with customer liquidity issues and bankruptcies;
•
customers, suppliers and other third parties seeking to terminate, reject, renegotiate or otherwise avoid, and otherwise failing to perform, their contractual obligations to us;
•
additional credit rating downgrades of our corporate debt and potentially higher borrowing costs in the future;
•
a need to preserve liquidity, which could result in a further reduction or suspension of our quarterly dividend or a delay or change in our capital investment plan;
•
cybersecurity issues, as digital technologies may become more vulnerable and experience a higher rate of cyberattacks in the current environment of remote connectivity;
•
litigation risk and possible loss contingencies related to COVID-19 and its impact, including with respect to commercial contracts, employee matters and insurance arrangements;
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disruption to our supply chain for raw materials essential to our business;
•
loss of workers and labor shortages;
•
general oilfield cost inflation, including increases in the cost of labor, services and supplies;

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•
a further reduction of our workforce to adjust to market conditions, including severance payments, retention issues, and an inability to hire employees when market conditions improve;
•
additional costs associated with rationalization of our portfolio of real estate facilities, including exit of leases and facility closures to align with expected activity and workforce capacity;
•
additional asset impairments, along with other accounting charges;
•
additional infections and quarantining of our employees and the personnel of our customers, suppliers and other third parties in areas in which we operate and delays or suspensions of operations resulting therefrom;
•
additional actions undertaken by international, national, regional and local governments and health officials, including mandates and testing, to contain the virus or treat its effects; and
•
a structural shift in the global economy and its demand for oil and natural gas as a result of changes in the way people work, travel and interact, or in connection with a global recession or depression.

The full extent of the impact of COVID-19 on our business, liquidity, results of operations and financial condition will depend largely on future developments, including the duration and further spread of the virus, including any new strains of COVID-19, and the related impact on the oil and gas industry, the impact of governmental actions designed to prevent the spread of COVID-19 and the further development, availability, timely distribution and acceptance of effective treatments and vaccines, all of which are highly uncertain.

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 in the United States. When these expenditures decline, our business may suffer. The rapid decline in oil prices resulting from the COVID-19 pandemic and the activities of OPEC+ caused a significant decline in both customer activity and prices for our services in 2020. While oil prices and demand for our services have recovered in 2021, activity has not fully recovered to its 2019 levels, and these events therefore continue to have, and are expected to continue to have, a significant impact on our business. 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:

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the supply of and demand for oil and natural gas, including current natural gas storage capacity and usage,
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the prices, and expectations about future prices, of oil and natural gas,
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the supply of and demand for drilling, pressure pumping and directional drilling services,
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the cost of exploring for, developing, producing and delivering oil and natural gas,
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the availability of capital for oil and natural gas industry participants, including our customers, and the extent to which they are willing or able to deploy capital,
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the availability of and constraints in pipeline, storage and other transportation capacity in the basins in which we operate,
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the environmental, tax and other laws and governmental regulations regarding the exploration, development, production, use and delivery of oil and natural gas, and in particular, public pressure on, and legislative and regulatory interest within, federal, state, foreign, regional and local governments to stop, significantly limit or regulate drilling and pressure pumping activities, including hydraulic fracturing,
•
increased focus by the investment and financing community on sustainability practices in the oil and natural gas industry, and
•
merger and divestiture activity among oil and natural gas producers.

In particular, our revenues, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas and expectations about future prices. Oil and natural gas prices and markets can be extremely volatile. Prices, and expectations about future prices, are affected by factors such as:

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market supply and demand, including impacts on supply and demand due to economic repercussions from the COVID-19 pandemic,
•
the desire and ability of the Organization of Petroleum Exporting Countries (“OPEC”), its members and other oil-producing nations, such as Russia, to set and maintain production and price targets,
•
the level of production by OPEC and non-OPEC countries,

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•
domestic and international military, political, economic, health and weather conditions, including the impacts of war or terrorist activity, pandemics and other unexpected disasters or events such as the COVID-19 pandemic,
•
changes to tax, tariff and import/export regulations by the United States or other countries,
•
legal and other limitations or restrictions on exportation and/or importation of oil and natural gas,
•
technical advances affecting energy consumption and production, and
•
the development, price, availability and market acceptance of alternative fuels and energy sources.

All of these factors are beyond our control. Oil prices remain extremely volatile, as the closing price of oil (WTI-Cushing) reached a first quarter 2020 high of $63.27 per barrel on January 6, 2020, declined to negative $36.98 per barrel on April 20, 2020, and recovered to reach a 2021 high of $85.64 per barrel on October 26, 2021. In response to the rapid decline in commodity prices, E&P companies acted swiftly to reduce drilling and completion activity starting late in the first quarter of 2020. While oil prices have recovered in 2021, and demand for our services has improved since the commodity price decline in 2020, our average number of rigs operating remains well below the number of our available rigs, and a significant portion of our pressure pumping horsepower remains stacked. Oil prices averaged $77.45 per barrel in the fourth quarter of 2021.

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

Global Economic Conditions May Adversely Affect Our Operating Results.

Concerns regarding global economic conditions, energy costs, geopolitical issues, supply chain disruptions, inflation, the availability and cost of credit and the COVID-19 pandemic 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, including economic repercussions from the COVID-19 pandemic, 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, including as a result of the COVID-19 pandemic, 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 due to uncertainties relating to the COVID-19 pandemic. A deterioration in the global economic environment could have a material adverse effect on our business, financial condition, cash flows and results of operations.

A Surplus of Equipment and a Highly Competitive Oil Service Industry May Adversely Affect Our Utilization and Profit Margins and the Carrying Value of our Assets.

The land drilling and pressure pumping industries in the United States are highly competitive, and at times available land drilling rigs and pressure pumping equipment exceed the demand for such equipment. A low commodity price environment or capital spending reductions by our customers due to customer consolidation, investor requirements or other reasons can result in substantially more drilling rigs and pressure pumping equipment being available than are needed to meet demand. In addition, in recent years there has been a substantial increase in new and upgraded drilling rigs and pressure pumping equipment. Low commodity prices and new and upgraded equipment can result in excess capacity and substantial competition for a declining number of drilling and pressure pumping contracts. Even in an environment of high oil and natural gas prices and/or increased drilling and completion activity, reactivation and improvement of existing drilling rigs and pressure pumping equipment, construction of new technology drilling rigs and new pressure pumping equipment, and movement of drilling rigs and pressure pumping equipment from region to region in response to market conditions or otherwise can lead to a surplus of equipment.

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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. With drilling and completion activity well below the peak seen in 2014 and many rigs, including highly capable AC-powered rigs, and pressure pumping equipment still idle, there are limitations on the ability to raise or maintain prices across our fleet. 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 without adversely affecting our activity levels. The inability to maintain our pricing and to increase our pricing as costs 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 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 in the oil and natural gas service businesses or the level of demand for our contract drilling, pressure pumping or directional drilling services.

The surplus of operable land drilling rigs, increasing rig specialization and surplus of pressure pumping and directional drilling equipment, which can be exacerbated by capital spending reductions by our customers, could affect the fair market value of our contract drilling, pressure pumping and directional drilling equipment, 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 $267 million, $423 million and $221 million in 2021, 2020 and 2019, 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, 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.

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We maintain insurance coverage of types and amounts that we believe to be customary in the industry, but we are not fully insured against all risks, either because insurance is not available or because of the high premium costs. The insurance coverage that we maintain includes insurance 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 and insurance for other specific risks. We cannot assure, however, that any insurance obtained by us will be adequate to cover any losses or liabilities, or that this insurance will continue to be available, or available on terms that are acceptable to us. 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 accept 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, a $2.0 million per occurrence deductible on our primary automobile liability insurance coverage, and a $5.0 million per occurrence deductible on our excess automobile liability insurance coverage. We also self-insure a number of other 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.

If a significant accident or other event occurs that is not fully covered by insurance or an enforceable and recoverable indemnity from a third party, it could have a material adverse effect on our business, financial condition, cash flows and results of operations.

Our Current Backlog of Contract Drilling Revenue May Decline and May Not Ultimately Be Realized, as Fixed-Term Contracts May in Certain Instances Be Terminated Without an Early Termination Payment.

Fixed-term drilling contracts customarily provide for termination at the election of the customer, with an early termination payment to us if a contract is terminated prior to the expiration of the fixed term. However, in certain circumstances, for example, destruction of a drilling rig that is not replaced within a specified period of time, our bankruptcy, or a breach of our contract obligations, the customer may not be obligated to make an early termination payment to us. Additionally, during depressed market conditions or otherwise, customers may be unable to satisfy their contractual obligations or may seek to terminate 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 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, 2021, our contract drilling backlog in the United States for future revenues under term contracts, which we define as contracts with a fixed term of six months or more, was approximately $325 million. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” 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 the 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.

New Technologies May Cause Our Operating Methods, Equipment and Services to Become Less Competitive, and Higher Levels of Capital Expenditures May Be Necessary to Remain Competitive.

The market for our services 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 rigs and pressure pumping and other equipment. Our customers are increasingly demanding the services of newer, higher specification drilling rigs and pressure pumping and other equipment, as well as new and improved technology, such as drilling automation technology and lower-emissions operations and services, and data analytics. Accordingly, we may have to allocate a higher proportion of our capital expenditures to maintain and improve existing rigs and pressure pumping and other equipment, purchase and construct newer, higher specification drilling rigs and pressure pumping and other equipment to meet the increasingly sophisticated needs of our customers, and develop new and improved technology 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 pressure pumping and directional drilling businesses could have similar effects.

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In recent years, we have added drilling rigs to our fleet through new construction and acquisitions, purchased new pressure pumping equipment and acquired a directional drilling services company. We have also improved existing drilling rigs and pressure pumping equipment by adding equipment and technology designed to enhance functionality and performance and reduce emissions. Although we take measures to ensure that we use advanced oil and natural gas drilling, pressure pumping and directional drilling technology, changes in technology, improvements in competitors’ equipment, increasing customer demands for new and improved technology, such as drilling automation technology and lower-emissions operations and services, and changes relating to the wells to be drilled and completed could make our equipment less competitive.

We continually attempt to develop new technologies for use in our business. 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 and services 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 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 personnel, particularly after a prolonged industry downturn. During periods of high demand for our services or inflation, wage rates for operations personnel are also likely to increase, resulting in higher operating costs. During periods of lower demand for our services, we may experience reductions in force and voluntary departures of key 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. We may also face a loss of workers and labor shortages as a result of quarantines, vaccine mandates or requirements and enforcement of other COVID-19 regulations in jurisdictions where we operate. 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 2021, we received approximately 57% from our ten largest customers and approximately 39% from our five largest customers and 16% 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, replacement parts and other equipment and materials, including, in the case of our pressure pumping operations, proppants, 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:

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effects of the COVID-19 pandemic,
•
weather issues, whether short-term such as a hurricane, or long-term such as a drought,
•
transportation and other logistical challenges, and

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a shortage in the number of vendors able or willing to provide the necessary equipment and materials, including as a result of commitments of vendors to other customers or third parties or bankruptcies or consolidation.

These price increases, delays in delivery and interruptions in supply may require us to delay operations, increase capital and repair expenditures or otherwise incur higher operating costs. During the COVID-19 pandemic, 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 operate, maintain, upgrade and construct our drilling rigs and pressure pumping and other equipment and could have a material adverse effect on our business, financial condition, cash flows and results of operations.

Our Business Is Subject to Cybersecurity Risks and Threats.

Our operations are increasingly dependent on effective and secure information technologies and services. 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 our data and systems, theft, viruses, malware, 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:

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theft or misappropriation of funds, including via “phishing” or similar attacks directed at us or our customers;
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loss, corruption, or misappropriation of intellectual property, or other proprietary or confidential information (including customer, supplier, or employee data);
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disruption or impairment of our and our customers’ business operations and safety procedures;
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personal injuries and destruction or damage to our and our customers’ property;
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downtime and loss of revenue;
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injury to our reputation, including the perception of our products or services as having security vulnerabilities;
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negative impacts on our ability to compete;
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loss or damage to our information technology systems, including operational technologies and worksite data delivery systems;
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exposure to litigation and legal and regulatory costs; and
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increased costs to prevent, respond to or mitigate cybersecurity events.

In response to the COVID-19 pandemic, many of our office personnel have moved to 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.

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 we cause third party service providers to 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 pressure pumping business, proppants. Some of these agreements are take-or-pay agreements with minimum purchase obligations. If demand for our services decreases from current levels, demand for the equipment that we use and the materials that we supply as part of these services will also decrease. In addition, our customers may self-source certain materials. If demand for our services and/or materials decreases enough, we could have contractual minimum commitments that exceed the required amount of materials we need to supply to our customers. In this instance, we could be required to purchase materials that we do not have a present need for, pay for materials that we do not take delivery of or pay prices in excess of market prices at the time of purchase.

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Growth Through Acquisitions, the Building or Upgrading of Equipment and the Development of Technology Is Not Assured.

We have grown our drilling rig fleet and pressure pumping fleet and expanded our business lines and use of technology in the past through mergers, acquisitions, upgrades, new construction and technology development. For example, we completed the Pioneer acquisition during 2021. 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 new technology. We are also likely to continue to face intense competition from other companies for available acquisition opportunities. In addition, because improved technology has enhanced the ability to recover oil and natural gas, our competitors may continue to upgrade and build new equipment and develop new technology, including drilling automation technology and lower-emissions operations and services.

There can be no assurance that we will:

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have sufficient capital resources to complete additional acquisitions, build or upgrade equipment or develop new technology,
•
successfully integrate additional equipment, acquired or developed technology or other assets or businesses, including Pioneer,
•
effectively manage the growth and increased size, complexity and geography of our organization, including as a result of the Pioneer acquisition,
•
successfully deploy idle, stacked, upgraded or additional equipment and acquired or developed technology,
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maintain the crews necessary to operate additional equipment or the personnel necessary to evaluate, acquire, develop and deploy new technology, or
•
successfully improve our financial condition, results of operations, business or prospects as a result of any completed acquisition, the building or upgrading equipment or the development of new technology.

Our failure to achieve consolidation savings, to integrate acquired businesses and technology and other assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our business. In addition, we may incur liabilities arising from events prior to any 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, these are 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 or building or upgrade program. 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 could strain our management, operations, employees and other resources.

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) could reduce demand for oil and natural gas and therefore for our services, which would lead to a reduction in our revenues.

Legal and Regulatory Risks

Potential Legislation and Regulation Covering Hydraulic Fracturing or Other Aspects of the Oil and Gas Industry Could Increase Our Costs and Limit or Delay Our Operations.

Numerous political and regulatory authorities, governmental bodies and officials, and environmental groups devote resources to campaigns aimed at eradicating hydraulic fracturing, a technology employed by our pressure pumping business, which involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production.

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President Biden and other political candidates and officeholders stated that they would support either increased regulation or a ban on hydraulic fracturing; however, we cannot predict whether hydraulic fracturing regulations will be enacted during the Biden Administration or how stringent they may be. In addition, members of the U.S. Congress and the EPA have reviewed proposals for more stringent regulation of hydraulic fracturing, and various state and local initiatives have been or may be proposed or implemented to further regulate hydraulic fracturing. In addition, a number of lawsuits have been filed against other industry participants alleging damages and regulatory violations in connection with such activity. These and other ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing and other aspects of the oil and gas industry.

In addition, legislation has been proposed, but not enacted, and may be proposed in the future, in the U.S. Congress to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process are impairing ground water or causing other damage. These bills, if enacted, could establish an additional level of regulation at the federal or state level that could limit or delay operational activities or increase operating costs and could result in additional regulatory burdens that could make it more difficult to perform or limit hydraulic fracturing and increase our costs of compliance and doing business.

Regulatory efforts at the federal level and in many states have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. These regulatory initiatives could each spur further action toward federal and/or state legislation and regulation of hydraulic fracturing activities. Certain states where we operate have adopted or are considering disclosure legislation and/or regulations, including a variety of well construction, set back and disclosure regulations limiting how fracturing can be performed and requiring various degrees of chemical disclosure.

Some parties believe that there is a correlation between hydraulic fracturing and other oilfield related activities and the increased occurrence of seismic activity. When caused by human activity, such seismic activity is called induced seismicity. The extent of this correlation, if any, is the subject of studies of both state and federal agencies. In light of concerns about induced seismicity, some state regulatory agencies have modified their regulations or issued orders to address induced seismicity.

Finally, several jurisdictions have taken steps to enact hydraulic fracturing bans, moratoria or increased regulations on hydraulic fracturing practices. These actions have been the subject of legal challenges.

The full impact of the foregoing actions remains unclear, but the adoption of any future federal, state, foreign, regional or local laws that impact permitting requirements for, result in reporting obligations on, or otherwise limit or ban, the hydraulic fracturing process could restrict our ability, or make it more difficult, to perform hydraulic fracturing and could increase our costs of compliance and doing business and reduce demand for our services. Regulation that significantly restricts or prohibits hydraulic fracturing could have a material adverse impact on our business, financial condition, cash flows and results of operations. Additionally, the adoption of significant restrictions or a prohibition on hydraulic fracturing by a state, region or locality could result in a surplus of oilfield equipment in other states, regions or localities where hydraulic fracturing remains allowed.

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 and tracking programs 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 DOT, implement GHG emissions limits on vehicles manufactured for operation in the United States.

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In April 2016, the United States signed 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 Unites 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, which currently controls Congress, have identified climate change as a priority, and it is likely that additional executive orders, regulatory action, and/or legislation targeting greenhouse gas emissions, or prohibiting or restricting oil and gas development activities in certain areas, will be proposed and/or promulgated during the Biden Administration. President Biden issued an executive order imposing a moratorium on new oil and gas leasing on federal lands and offshore waters pending completion of a comprehensive review and reconsideration of federal oil and 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. 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.

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.

There are also increasing financial risks for oil and natural gas producers, as stockholders and bondholders currently invested in oil and natural gas companies 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 increasing pressure regarding our ESG practices and disclosures, which pressures have intensified recently in connection with the COVID-19 pandemic, significant societal events and worldwide efforts to mitigate climate change. Additionally, 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. 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, or if we are unable to successfully continue our sustainability enhancement efforts, 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.

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 operations.

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Environmental and Occupational Health and Safety Laws and Regulations, Including Violations Thereof, Could Materially Adversely Affect Our Operating Results.

Our business is subject to numerous federal, state, foreign, regional and local laws, rules and regulations governing the discharge of substances into the environment, protection of the environment and worker health and safety, including, without limitation, laws concerning the containment and disposal of hazardous substances, oil field waste and other waste materials, the use of underground storage tanks, and the use of underground injection wells. The cost of compliance with these laws and regulations could be substantial. A failure to comply with these requirements could expose us to:

•
substantial civil, criminal and/or administrative penalties or judgments,
•
modification, denial or revocation of permits or other authorizations,
•
imposition of limitations on our operations, and
•
performance of site investigatory, remedial or other corrective actions.

In addition, environmental laws and regulations in the places that we operate impose a variety of requirements on “responsible parties” related to the prevention of spills and liability for damages from such spills. As an owner and operator of land-based drilling rigs and pressure pumping 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.

Technology Disputes Could Negatively Impact Our Operations or Increase Our Costs.

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 rigs, pressure pumping equipment and directional drilling services 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. 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. 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.

The Design, Manufacture, Sale and Servicing of Products, including 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 electrical controls, to customers involved in oil and 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.

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. Additionally, actions or decisions we have taken or may take as a consequence of the COVID-19 pandemic may result in investigations, litigation or legal claims 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.”

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Political, Economic and Social Instability Risk and Laws Associated with Conducting International Operations Could Adversely Affect Our Opportunities and Future Business.

We provide contract drilling services in Colombia, we sell products, including electrical controls, for use in numerous oil and gas producing regions outside of North America, and 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 other services outside of the United States. International operations 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, 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 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 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 believe that neither operating through such entities nor pursuant to such arrangements would have a material adverse effect on our operations or revenues, there can be no assurance that we will in all cases be able to structure or restructure our operations to conform to local law (or the administration thereof) on terms we find acceptable. Additionally, we may be subject to foreign governmental regulations favoring or requiring the awarding of contracts to local contractors or requiring foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These regulations could adversely affect our ability to compete.

There can be no assurance that we will:

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identify attractive opportunities in international markets,
•
have sufficient capital resources to pursue and consummate international opportunities,
•
successfully integrate international drilling rigs, pressure pumping equipment or other assets or businesses, such as the Colombia contract drilling business acquired through the Pioneer acquisition,
•
effectively manage the start-up, development and growth of an international organization and assets,
•
hire, attract and retain the personnel necessary to successfully conduct international operations, or
•
receive awards for work and successfully improve our financial condition, results of operations, business or prospects as a result of the entry into one or more international markets.

In addition, the U.S. Foreign Corrupt Practices Act (“FCPA”) and similar anti-bribery laws in other jurisdictions generally prohibit companies and their intermediaries from making improper payments to foreign officials for the purpose of obtaining or retaining business. Some parts of the world where our services 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, pressure pumping equipment or other assets.

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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 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.

Financial Risks

We Are Dependent Upon Our Subsidiaries to Meet our Obligations Under Our Long-Term Debt.

We have borrowings outstanding under our senior notes and, from time to time, our revolving credit facility. Our ability to meet our interest and principal payment obligations depends in large part on cash flows from our subsidiaries. If our subsidiaries do not generate sufficient cash flows, we may be unable to meet our interest and principal payment obligations.

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, LIBOR or a base rate. The applicable margin on LIBOR rate loans varies from 1.00% to 2.00% and the applicable margin on base rate loans varies from 0.00% to 1.00%, in each case determined based upon our credit rating. As of December 31, 2021, the applicable margin on LIBOR rate loans was 1.75% and the applicable margin on base rate loans was 0.75%. As of December 31, 2021, 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, 2021, no amounts had been disbursed under any letters of credit.

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.

A Downgrade in Our Credit Rating Could Negatively Impact Our Cost of and Ability to Access Capital.

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, including the impact of the COVID-19 pandemic. A ratings downgrade could adversely impact our ability in the future to access debt markets, increase the cost of future debt, 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, 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.

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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.

Risks Related to Our Common Stock and Corporate Structure

The Market Price of Our Common Stock May Be Highly Volatile, and Investors May Not Be Able to Resell Shares at or Above the Price Paid.

The trading price of our common stock may be volatile. Securities markets worldwide experience significant price and volume fluctuations. This market volatility, as well as other general economic, market or political conditions, could reduce the market price of our common stock in spite of our operating and/or financial performance. The following factors, in addition to other factors described in this “Risk Factors” section and elsewhere in this Report, may have a significant impact on the market price of our common stock:

•
investor perception of us and the industry and markets in which we operate;
•
general financial, domestic, international, economic, and market conditions, including overall fluctuations in the U.S. equity markets;
•
increased focus by the investment community on sustainability practices at our company and in the oil and natural gas industry generally;
•
changes in customer needs, expectations or trends and our ability to maintain relationships with key customers;
•
our ability to implement our business strategy;
•
changes in our capital structure, including the issuance of additional debt;
•
public announcements (including the timing of these announcements) regarding our business, financial performance and prospects or new services or products, service or product enhancements, technological advances or strategic actions, such as acquisitions or divestitures, restructurings or significant contracts, by our competitors or us;
•
trading activity in our stock, including portfolio transactions in our stock by us, our executive officers and directors, and significant stockholders or trading activity that results from the ordinary course rebalancing of stock indices in which we may be included;
•
short-interest in our common stock, which could be significant from time to time;
•
our inclusion in, or removal from, any stock indices;
•
changes in earnings estimates or buy/sell recommendations by securities analysts;
•
whether or not we meet earnings estimates of securities analysts who follow us; and
•
regulatory or legal developments in the United States and foreign countries where we operate.

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.

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Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties

Our property consists primarily of drilling rigs, pressure pumping equipment and related equipment. 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. Our primary administrative office, which is located in Snyder, Texas, is owned and includes approximately 37,000 square feet of office and storage space.

Contract Drilling — 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.

Pressure Pumping — Our pressure pumping services are supported by multiple offices and yard facilities located in Texas and Pennsylvania.

Directional Drilling — Our directional drilling services are supported by multiple offices and yard facilities located throughout our areas of operations, including Texas, North Dakota, and Ohio.

Our oilfield rental operations are supported by offices and yard facilities located in Texas, Oklahoma and Ohio. 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. Our interests in oil and natural gas properties are primarily located in Texas and New Mexico.

We own our administrative offices in Snyder, Texas, as well as several other facilities. We also lease a number of facilities, and we do not believe that any one of the leased facilities is individually material to our operations. We believe that our existing facilities are suitable and adequate to meet our needs.

We incorporate by reference in response to this item the information set forth in Item 1 of this Report and the information set forth in Note 6 of the Notes to Consolidated Financial Statements included in Item 8 of this Report.

Item 3. Legal Proceedings.

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

Item 4. Mine Safety Disclosure.

Not applicable.

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PART II

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

(a) Market Information

Our common stock, par value $0.01 per share, is publicly traded on the Nasdaq Global Select Market and is quoted under the symbol “PTEN.” Our common stock is included in the S&P SmallCap 600 Index and several other market indices.

(b) Holders

As of February 10, 2022, there were approximately 1,000 holders of record of our common stock.

(c) Dividends

On February 9, 2022, our Board of Directors approved a cash dividend on our common stock in the amount of $0.04 per share to be paid on March 17, 2022 to holders of record as of March 3, 2022. The amount and timing of all future dividend payments, if any, are subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of our debt agreements and other factors. Our Board of Directors may, without advance notice, reduce or suspend our dividend in order to improve our financial flexibility and best position our company for long-term success. There can be no assurance that we will pay a dividend in the future.

(d) Issuer Purchases of Equity Securities

The table below sets forth the information with respect to purchases of our common stock made by us during the quarter ended December 31, 2021.

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 2021 |  |  | 291,926 |  |  | $ | 9.42 |  |  |  | — |  |  | $ | 130,000 |
November 2021 |  |  | — |  |  | $ | — |  |  |  | — |  |  | $ | 130,000 |
December 2021 |  |  | 523 |  |  | $ | 8.01 |  |  |  | — |  |  | $ | 130,000 |
Total |  |  | 292,449 |  |  |  |  |  |  | — |  |  |  |

(1)
Upon the issuance of shares for the Pioneer acquisition in October 2021, we withheld 275,477 shares with respect to Pioneer employees’ tax withholding obligations. In addition, we withheld 16,972 shares in the fo urth quarter with respect to employees’ tax withholding obligations upon the vesting of restricted stock units. These shares were acquired at fair market value. Acquisitions of 16,972 shares were made pursuant to the terms of the Amended and Restated 2014 Long-Term Incentive Plan, as amended and the 2021 Long-Term Incentive Plan, and not pursuant to the stock buyback program.

(2)
On September 9, 2013, we announced that our Board of Directors approved a stock buyback program authorizing purchases of up to $200 million of our common stock in open market or privately negotiated transactions. On July 26, 2018, we announced that our Board of Directors approved an increase of the authorization under the stock buyback program to allow for $250 million of future share repurchases. On February 7, 2019, we announced that our Board of Directors approved another increase of the authorization under the stock buyback program to allow for $250 million of future share repurchases. On July 25, 2019, we announced that our Board of Directors approved another increase of the authorization under the stock buyback program to allow for $250 million of future share repurchases. All purchases executed to date have been through open market transactions. Purchases under the program are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Purchases may be made at any time without prior notice. Shares of stock purchased under the buyback program are held as treasury shares. There is no expiration date associated with the buyback program.

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(e) Performance Graph

The following graph compares the cumulative stockholder return of our common stock for the period from December 31, 2016 through December 31, 2021, with the cumulative total return of the S&P 500 Index, the S&P SmallCap 600 Index, the Oilfield Service Index and a peer group determined by us. We changed our peer group in 2021 to align with the peer group used by the compensation committee of our Board of Directors. Our new peer group consists of Archrock, Inc., Bristow Group Inc., Cactus, Inc., ChampionX Corp., EQT Corporation, Helix Energy Solutions Group, Inc., Helmerich & Payne, Inc., Liberty Oilfield Services, Inc., Nabors Industries Ltd., NexTier Oilfield Solutions, Inc., NOV Inc., Oceaneering International, Inc., Oil States International, Inc., PDC Energy, Inc., Precision Drilling Corporation, Range Resources Corporation, TechnipFMC Plc. and Transocean Ltd. Our old peer group consisted of ChampionX Corporation, Archrock, Inc., Cimarex Energy Co., Diamond Offshore Drilling, Inc., EQT Corporation, Helmerich & Payne, Inc., Liberty Oilfield Services, Inc., Nabors Industries Ltd., NexTier Oilfield Solutions, Inc., NOV Inc., Noble Corporation plc., Oceaneering International, Inc., Oil States International, Inc., PDC Energy, Inc., Precision Drilling Corporation, Range Resources Corporation, TechnipFMC Plc, Transocean Ltd., Valaris plc and WPX Energy, Inc.

The graph assumes investment of $100 on December 31, 2016 and reinvestment of all dividends.

Index Data: Copyright Standard and Poor’s, Inc. Used with permission. All rights reserved.

|  | Fiscal Year Ended December 31, |
|  | 2016 |  |  | 2017 |  |  | 2018 |  |  | 2019 |  |  | 2020 |  |  | 2021 |
Company/Index |  | ($) |  |  | ($) |  |  | ($) |  |  | ($) |  |  | ($) |  |  | ($) |
Patterson-UTI Energy, Inc. |  |  | 100.00 |  |  |  | 85.80 |  |  |  | 38.93 |  |  |  | 40.13 |  |  |  | 20.54 |  |  |  | 33.34 |
S&P 500 Stock Index |  |  | 100.00 |  |  |  | 121.83 |  |  |  | 116.49 |  |  |  | 153.17 |  |  |  | 181.35 |  |  |  | 233.41 |
S&P SmallCap 600 Index |  |  | 100.00 |  |  |  | 113.23 |  |  |  | 103.63 |  |  |  | 127.24 |  |  |  | 141.60 |  |  |  | 179.58 |
Oilfield Service Index |  |  | 100.00 |  |  |  | 82.80 |  |  |  | 45.36 |  |  |  | 45.11 |  |  |  | 26.13 |  |  |  | 31.55 |
Old Peer Group Index |  |  | 100.00 |  |  |  | 80.92 |  |  |  | 50.44 |  |  |  | 48.07 |  |  |  | 27.64 |  |  |  | 38.21 |
New Peer Group Index |  |  | 100.00 |  |  |  | 78.34 |  |  |  | 49.73 |  |  |  | 49.38 |  |  |  | 29.21 |  |  |  | 37.66 |

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.

30

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

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

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

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

Oil prices remain extremely volatile, as the closing price of oil (WTI-Cushing) reached a first quarter 2020 high of $63.27 per barrel on January 6, 2020, declined to negative $36.98 per barrel on April 20, 2020, and recovered to reach a 2021 high of $85.64 per barrel on October 26, 2021. In response to the rapid decline in commodity prices, E&P companies acted swiftly to reduce drilling and completion activity starting late in the first quarter of 2020. While oil prices have recovered in 2021, and demand for our services has improved since the commodity price decline in 2020, our average number of rigs operating remains well below the number of our available rigs, and a significant portion of our pressure pumping horsepower remains stacked. Oil prices averaged $77.45 per barrel in the fourth quarter of 2021.

Quarterly average oil prices and our quarterly average number of rigs operating in the United States for 2019, 2020 and 2021 are as follows:

|  | 1 st |  |  | 2 nd |  |  | 3 rd |  |  | 4 th |
|  | Quarter |  |  | Quarter |  |  | Quarter |  |  | Quarter |
2019: |  |  |  |  |  |  |  |  |  |  |  |
Average oil price per Bbl (1) |  | $ | 54.83 |  |  | $ | 59.78 |  |  | $ | 56.37 |  |  | $ | 56.94 |
Average rigs operating per day - U.S. (2) |  |  | 174 |  |  |  | 157 |  |  |  | 142 |  |  |  | 122 |
2020: |  |  |  |  |  |  |  |  |  |  |  |
Average oil price per Bbl (1) |  | $ | 45.76 |  |  | $ | 27.81 |  |  | $ | 40.89 |  |  | $ | 42.45 |
Average rigs operating per day - U.S. (2) |  |  | 123 |  |  |  | 82 |  |  |  | 60 |  |  |  | 62 |
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 |

(1)
The average oil price represents the average monthly WTI spot price as reported by the United States Energy Information Administration.
(2)
A rig is considered to be operating if it is earning revenue pursuant to a contract on a given day.

Although our active rig count has not fully recovered to its 2019 levels, it increased in 2021 after a significant decline in 2020. Our average active rig count in the U.S. for the fourth quarter of 2021 was 106 rigs. This was an increase from our average active rig count for the third quarter of 2021 of 80 rigs. The increase was partially due to our acquisition of active U.S. rigs from Pioneer, which averaged 13 active rigs during the fourth quarter of 2021. Our active U.S. rig count at December 31, 2021 of 111 rigs was more than the rig count of 65 rigs at December 31, 2020, partially due to the increase in rigs from the Pioneer acquisition and, more significantly, due to the recovery of oil prices and improved demand for drilling services in the United States. Term contracts help support our operating rig count. Based on contracts currently in place in the United States, we expect an average of 51 rigs operating under term contracts during the first quarter, and an average of 39 rigs operating under term contracts during 2022.

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We ended the fourth quarter of 2021 with 11 active pressure pumping spreads compared to ten at the end of the third quarter. Our average active spread count was approximately ten spreads and effective utilization was close to 11 spreads for the fourth quarter of 2021. We calculated average active spreads as the average number of spreads that were crewed and actively marketed during the period, and we calculated effective utilization as total pumping days during the quarter divided by 75 days, which we consider full effective utilization for a spread for the period. We expect to average approximately 11 active spreads in the first quarter of 2022. The pressure pumping market has improved but remains oversupplied.

Due to improving activity levels and increasing tightness in the overall labor market, we saw general oilfield cost inflation across our segments during 2021, including increases in the cost of labor, services and supplies. This inflation, combined with the increasing challenge of attracting employees to the industry, is increasing the complexity of reactivating equipment. We believe this challenge, combined with the increasing market tightness for premium drilling and completion services, will support higher pricing for our services in 2022. During 2021, we increased our capital expenditure forecast to approximately $170 million, in part, based on conversations with customers about increasing activity levels into 2022. Actual 2021 capital expenditures excluding discontinued operations totaled $166 million.

Recent Developments in Financial Matters and Merger and Acquisition Activity — 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 gas exploration and production companies in the United States and internationally in Colombia. Through the Pioneer acquisition, we acquired Pioneer’s 100% pad-capable drilling rig fleet consisting of 17 AC-powered rigs in the United States and eight SCR rigs in Colombia and production services assets consisting of 123 well servicing rigs and 72 wireline services units. We believe the acquisition of Pioneer enhances our position as a leading provider of contract drilling services in the United States and expands our geographic footprint into Latin America.

On December 31, 2021, we completed the sale of Pioneer Production Services to Clearwell. The sale price was $43.0 million in cash consideration, subject to customary purchase price adjustments at closing for cash and working capital. The results of operations of these businesses have been presented as a discontinued operation in these consolidated financial statements. In connection with the sale of our Pioneer Production Services business, we entered into a transition services agreement with Clearwell, pursuant to which we agreed to provide each other certain administrative and operational services on an interim, transitional basis through June 30, 2022.

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

During the fourth quarter of 2020, we elected to repurchase portions of our 2028 Notes and 2029 Notes (as defined below) in the open market. The principal amounts retired through these transactions totaled $15.5 million related to our 2028 Notes and $0.8 million related to our 2029 Notes, plus accrued interest. We recorded corresponding gains on the extinguishment of these amounts totaling $3.4 million and $0.2 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 the consolidated statements of operations.

On March 27, 2020, we entered into Amendment No. 2 to Amended and Restated Credit Agreement (“Amendment No. 2”) to, among other things, extend the maturity date for $550 million of revolving credit commitments of certain lenders under the Credit Agreement (as defined below) from March 27, 2024 to March 27, 2025. We have the option, subject to certain conditions, to exercise an additional one-year extension of the maturity date.

During the second quarter of 2020, we implemented a restructuring plan to improve operating margins, achieve operational efficiencies and reduce indirect support costs. The restructuring included workforce reductions, changes to management structure and facility consolidations and closures. We recorded $38.3 million of charges associated with this plan in the second quarter of 2020. We completed the restructuring plan during the third quarter of 2020 and did not incur additional expenses related to the plan. There have been no restructuring charges in 2021.

Our revenues, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas and upon our customers’ ability to access capital to fund their operating and capital expenditures. During periods of improved oil and natural gas prices, the capital spending budgets of oil and natural gas operators tend to expand, which generally results in increased demand for our services. Conversely, in periods when oil and natural gas prices are relatively low or when our customers have a reduced ability to access capital, the demand for our services generally weakens, and we experience downward pressure on pricing for our services. We may also be impacted by delayed customer payments and payment defaults associated with customer liquidity issues and bankruptcies.

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

In addition to the dependence on oil and natural gas prices and demand for our services, we are highly impacted by operational risks, competition, labor issues, weather, the availability, from time to time, of products used in our pressure pumping business, supplier delays and various other factors that could materially adversely affect our business, financial condition, cash flows and results of operations, including as a result of the COVID-19 pandemic. See “Risk Factors” in Item 1A of this Report.

For the three years ended December 31, 2021, our operating revenues consisted of the following (dollars in thousands):

|  | 2021 |  |  | 2020 |  |  | 2019 |
Contract drilling |  | $ | 664,030 |  |  |  | 48.9 | % |  | $ | 669,126 |  |  |  | 59.5 | % |  | $ | 1,308,350 |  |  |  | 53.0 | %
Pressure pumping |  |  | 523,756 |  |  |  | 38.6 | % |  |  | 336,111 |  |  |  | 29.9 | % |  |  | 868,694 |  |  |  | 35.2 | %
Directional drilling |  |  | 111,481 |  |  |  | 8.2 | % |  |  | 73,356 |  |  |  | 6.5 | % |  |  | 188,786 |  |  |  | 7.6 | %
Other |  |  | 57,814 |  |  |  | 4.3 | % |  |  | 45,656 |  |  |  | 4.1 | % |  |  | 104,855 |  |  |  | 4.2 | %
|  | $ | 1,357,081 |  |  |  | 100.0 | % |  | $ | 1,124,249 |  |  |  | 100.0 | % |  | $ | 2,470,685 |  |  |  | 100.0 | %

Contract Drilling

We have addressed our customers’ needs for drilling horizontal wells in shale and other unconventional resource plays by improving the capabilities of our drilling fleet during the last several years. The U.S. land rig industry 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 have begun to refer to certain premium rigs as “Tier-1, super spec” rigs, which we consider as being a super-spec rig that also has a third mud pump and raised drawworks that allow for more clearance underneath the rig floor. As of December 31, 2021, our rig fleet included 171 super-spec rigs, of which 107 were Tier-1, super-spec rigs.

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, 2021 and 2020 was approximately $325 million and $301 million, respectively. Approximately 22% of the total contract drilling backlog in the United States at December 31, 2021 is reasonably expected to remain after 2022. We generally calculate our backlog by multiplying the dayrate under our term drilling contracts by the number of days remaining under the contract. The calculation does not include any revenues related to fees for other services such as for mobilization, other than initial mobilization, demobilization and customer reimbursables, nor does it include potential reductions in rates for unscheduled standby or during periods in which the rig is moving or incurring maintenance and repair time in excess of what is permitted under the drilling contract. For contracts that contain variable dayrate pricing, our backlog calculation uses the dayrate in effect for periods where the dayrate is fixed, and, for periods that remain subject to variable pricing, uses the commodity price in effect at December 31, 2021. In addition, our term drilling contracts are generally subject to termination by the customer on short notice and provide for an early termination payment to us in the event that the contract is terminated by the customer. For contracts on which we have received notice for the rig to be placed on standby, our backlog calculation uses the standby rate for the period over which we expect to receive the standby rate. For contracts on which we have received an early termination notice, our backlog calculation includes the early termination rate, instead of the dayrate, for the period over which we expect to receive the lower rate. See “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.”

Pressure Pumping

As of December 31, 2021, we had approximately 1.1 million horsepower in our pressure pumping fleet. The pressure pumping market has improved but remains oversupplied. In response to oversupplied market conditions, we implemented changes during the second quarter of 2020 that were intended to further streamline our operations, improve our efficiencies, and reduce our overall cost structure, while maintaining our customer service levels.

Directional Drilling

We provide a comprehensive suite of directional drilling services in most major producing onshore oil and gas basins in the United States. Our directional drilling services include directional drilling, measurement-while-drilling and supply and rental of downhole performance motors. We also provide services that improve the statistical accuracy of directional and horizontal wellbores.

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Other Operations

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 gas assets located in Texas and New Mexico, provide the largest revenue contributions to our other operations. Other operations also includes the results of our electrical controls and automation business and the results of our drilling equipment service business.

Capital Expenditures

Cash capital expenditures for 2021, excluding discontinued operations, totaled $166 million. This was an increase from the $145 million of cash capital expenditures for 2020, due largely to higher activity levels in 2021. Based on our current outlook for activity, we expect our capital expenditures for 2022 to be approximately $350 million.

For the three years ended December 31, 2021, our operating losses consisted of the following (dollars in thousands):

|  | 2021 |  |  | 2020 |  |  | 2019 |
Contract drilling |  | $ | (423,029 | ) |  |  | 62.4 | % |  | $ | (543,438 | ) |  |  | 60.9 | % |  | $ | (151,329 | ) |  |  | 32.8 | %
Pressure pumping |  |  | (118,863 | ) |  |  | 17.5 | % |  |  | (166,666 | ) |  |  | 18.7 | % |  |  | (102,701 | ) |  |  | 22.3 | %
Directional drilling |  |  | (35,301 | ) |  |  | 5.2 | % |  |  | (40,612 | ) |  |  | 4.6 | % |  |  | (52,724 | ) |  |  | 11.4 | %
Other |  |  | (9,905 | ) |  |  | 1.5 | % |  |  | (41,685 | ) |  |  | 4.7 | % |  |  | (54,725 | ) |  |  | 11.9 | %
Corporate |  |  | (90,652 | ) |  |  | 13.4 | % |  |  | (99,857 | ) |  |  | 11.1 | % |  |  | (100,097 | ) |  |  | 21.6 | %
|  | $ | (677,750 | ) |  |  | 100.0 | % |  | $ | (892,258 | ) |  |  | 100.0 | % |  | $ | (461,576 | ) |  |  | 100.0 | %

While demand for our services improved in 2021, our average number of rigs operating remains well below the number of our available rigs, and a significant portion of our pressure pumping horsepower remains stacked. This reduced demand, combined with impairments to our contract drilling, pressure pumping and directional drilling equipment contributed to a consolidated net loss of $655 million for 2021, compared to a consolidated net loss of $804 million for 2020 and consolidated net loss of $426 million for 2019.

Results of Operations

Comparison of the years ended December 31, 2021 and 2020

The following tables summarize results of operations by business segment for the years ended December 31, 2021 and 2020:

|  | Year Ended December 31, |
Contract Drilling |  | 2021 |  |  | 2020 |  |  | % Change |
|  | (Dollars in thousands) |
Revenues |  | $ | 664,030 |  |  | $ | 669,126 |  |  |  | (0.8 | )%
Direct operating costs |  |  | 463,456 |  |  |  | 380,822 |  |  |  | 21.7 | %
Adjusted gross margin (1) |  |  | 200,574 |  |  |  | 288,304 |  |  |  | (30.4 | )%
Restructuring expenses |  |  | — |  |  |  | 2,430 |  |  | NA |
Other operating expenses (income), net |  |  | 25 |  |  |  | (4,185 | ) |  | NA |
Selling, general and administrative |  |  | 4,699 |  |  |  | 4,666 |  |  |  | 0.7 | %
Depreciation, amortization and impairment |  |  | 618,879 |  |  |  | 433,771 |  |  |  | 42.7 | %
Impairment of goodwill |  |  | — |  |  |  | 395,060 |  |  | NA |
Operating loss |  | $ | (423,029 | ) |  | $ | (543,438 | ) |  |  | (22.2 | )%
Operating days - U.S. (2) |  |  | 29,960 |  |  |  | 29,857 |  |  |  | 0.3 | %
Average revenue per operating day - U.S. |  | $ | 21.64 |  |  | $ | 22.38 |  |  |  | (3.3 | )%
Average direct operating costs per operating day - U.S. |  | $ | 15.11 |  |  | $ | 12.68 |  |  |  | 19.2 | %
Average adjusted gross margin per operating day - U.S. (1) |  | $ | 6.53 |  |  | $ | 9.70 |  |  |  | (32.7 | )%
Average rigs operating - U.S. |  |  | 82 |  |  |  | 82 |  |  |  | 0.6 | %
Capital expenditures |  | $ | 109,894 |  |  | $ | 105,037 |  |  |  | 4.6 | %

(1)
Adjusted gross margin is defined as revenues less direct operating costs and excludes restructuring expenses, other operating expenses (income), net, selling, general and administrative expenses, depreciation, amortization and impairment and impairment of goodwill. Average adjusted gross margin per operating day is defined as adjusted gross margin divided by operating days
(2)
A rig is considered to be operating if it is earning revenue pursuant to a contract on a given day.

Reduced demand for crude oil and refined products related to the COVID-19 pandemic, combined with production increases from OPEC+, led to a significant reduction in crude oil prices and demand for contract drilling services in 2020 and early 2021.

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Generally, the revenues in our contract drilling segment are most impacted by two primary factors: our average number of rigs operating and our average revenue per operating day. Our average revenue per operating day is largely dependent on the pricing terms of our rig contracts. Lump sum early termination revenues were $4.1 million in 2021, which was less than the $13.3 million recorded during the comparable period of 2020.

Revenues remained relatively flat in 2021 as compared to 2020 despite this reduction in lump sum early termination revenues. However, $41.5 million of our revenues in 2021 related to additional drilling rigs from the Pioneer acquisition. Without the impact of the Pioneer acquisition, 2021 revenues would have been approximately $623 million, a 7% decrease, and operating days from our U.S. operations would have been 28,722, a 3.8% decrease from 2020. The reduction in lump sum early termination revenues from 2020 resulted in an incremental 1.4% decrease. Average revenue per operating day excluding the effects of the Pioneer acquisition did not change significantly.

The Pioneer acquisition added $30.5 million of direct operating costs in 2021, which contributed to an 8.0% increase as compared to 2020. Apart from the increase attributed to the Pioneer acquisition, direct operating costs increased $52.2 million, or 13.7%, as compared to 2020. Apart from the Pioneer acquisition, average direct operating costs per operating day in the U.S. were $15,069, an 18.8% increase. The increases in direct operating costs and average direct operating costs per day were primarily due to a reduction in the proportion of rigs on standby and rig reactivation costs. Rigs on standby have very little associated cost.

Restructuring expenses were recognized in 2020 and primarily related to severance costs. See Note 20 of Notes to Consolidated Financial Statements included in Item 8 of this Report.

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

Depreciation, amortization and impairment expense increased primarily due to a $220 million impairment charge related to abandonment of 43 legacy non-super-spec rigs and equipment. 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. In the second quarter of 2020 we recorded an impairment of $8.3 million related to the closing of our Canadian drilling operations. Without the impairment charge in 2021, depreciation and amortization expense would have decreased to approximately $399 million, an 8.1% decrease as compared to 2020. The decrease excluding impairment was due to lower cumulative capital expenditures in recent years, which reduced our depreciable asset base as depreciation, amortization and impairment outpaced capital expenditures between the periods. This decline was partially offset by incremental depreciation and amortization associated with the additional rigs from the Pioneer acquisition, which contributed three months of expense after the October 1, 2021 closing date.

All of the goodwill associated with our contract drilling reporting unit was impaired in 2020. See Note 7 of Notes to Consolidated Financial Statements included as a part of Item 8 of this Report.

|  | Year Ended December 31, |
Pressure Pumping |  | 2021 |  |  | 2020 |  |  | % Change |
|  | (Dollars in thousands) |
Revenues |  | $ | 523,756 |  |  | $ | 336,111 |  |  |  | 55.8 | %
Direct operating costs |  |  | 475,953 |  |  |  | 310,261 |  |  |  | 53.4 | %
Adjusted gross margin (1) |  |  | 47,803 |  |  |  | 25,850 |  |  |  | 84.9 | %
Restructuring expenses |  |  | — |  |  |  | 31,331 |  |  | NA |
Selling, general and administrative |  |  | 7,361 |  |  |  | 8,555 |  |  |  | (14.0 | )%
Depreciation, amortization and impairment |  |  | 159,305 |  |  |  | 152,630 |  |  |  | 4.4 | %
Operating loss |  | $ | (118,863 | ) |  | $ | (166,666 | ) |  |  | (28.7 | )%
Average active spreads (2) |  |  | 8 |  |  |  | 6 |  |  |  | 38.3 | %
Effective utilization (3) |  |  | 8.7 |  |  |  | 5.6 |  |  |  | 55.4 | %
Fracturing jobs |  |  | 422 |  |  |  | 265 |  |  |  | 59.2 | %
Other jobs |  |  | 754 |  |  |  | 736 |  |  |  | 2.4 | %
Total jobs |  |  | 1,176 |  |  |  | 1,001 |  |  |  | 17.5 | %
Average revenue per fracturing job |  | $ | 1,187.29 |  |  | $ | 1,188.46 |  |  |  | (0.1 | )%
Average revenue per other job |  | $ | 30.13 |  |  | $ | 28.76 |  |  |  | 4.8 | %
Average revenue per total job |  | $ | 445.37 |  |  | $ | 335.78 |  |  |  | 32.6 | %
Average direct operating costs per total job |  | $ | 404.72 |  |  | $ | 309.95 |  |  |  | 30.6 | %
Average adjusted gross margin per total job (1) |  | $ | 40.65 |  |  | $ | 25.82 |  |  |  | 57.4 | %
Adjusted gross margin as a percentage of revenues (1) |  |  | 9.1 | % |  |  | 7.7 | % |  |  | 18.2 | %
Capital expenditures |  | $ | 34,676 |  |  | $ | 21,678 |  |  |  | 60.0 | %

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(1)
Adjusted gross margin is defined as revenues less direct operating costs and excludes restructuring expenses, selling, general and administrative expenses and depreciation, amortization and impairment. Average adjusted gross margin per total job is defined as adjusted gross margin divided by total jobs. Adjusted gross margin as a percentage of revenues is defined as adjusted gross margin divided by revenues.
(2)
Average active spreads is the average number of spreads that were crewed and actively marketed during the period.
(3)
Effective utilization is calculated as total pumping days during the year divided by 300 days, which we consider full effective utilization for a year.

Reduced demand for crude oil and refined products related to the COVID-19 pandemic, combined with production increases from OPEC+, led to a significant reduction in crude oil prices and demand for pressure pumping services in 2020 and early 2021.

Generally, the revenues in our pressure pumping segment are most impacted by our number of fracturing jobs and the size (including whether or not we provide proppant and other materials) of those jobs, which is reflected in our average revenue per fracturing job. Direct operating costs are also most impacted by these same factors. Our average revenue per fracturing job is largely dependent on the pricing terms of our pressure pumping contracts and the size of the jobs.

Revenues and direct operating costs increased primarily due to an increase in fracturing jobs as activity levels continue to recover from the industry downturn in 2020. Average revenue per total job increased primarily due to a mix of activity weighted toward higher revenue fracturing jobs. Average direct operating costs per total job increased also as a result of the significant increase in fracturing jobs, which generally have higher direct operating costs. We exited 2021 with 11 active spreads as compared to five active spreads on December 31, 2020.

Restructuring expenses were recognized in the second quarter of 2020. These restructuring expenses included $7.3 million related to right-of-use asset abandonments, $3.5 million of severance costs and $20.4 million of contract termination costs. See Note 20 of Notes to Consolidated Financial Statements in Item 8 of this Report.

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

Depreciation, amortization and impairment expense increased as a result of a $32.2 million impairment charge related to the abandonment of approximately 0.2 million horsepower within our pressure pumping fleet. The majority of these units were frac pumps but also included pump down units. These units were abandoned due to a combination of customer preference for dual fuel units, advancements in technology, and prohibitive reactivation costs. Excluding the impairment charge in 2021, depreciation and amortization would have been $127 million, a 16.7% decline. The decrease excluding impairment is due to lower cumulative capital expenditures in recent years, which reduced our depreciable asset base as depreciation, amortization and impairment outpaced capital expenditures between periods.

Capital expenditures increased due to increased maintenance capital, mostly related to engines and transmissions as well as higher inflationary pressure on replacement items.

|  | Year Ended December 31, |
Directional Drilling |  | 2021 |  |  | 2020 |  |  | % Change |
|  | (Dollars in thousands) |
Revenues |  | $ | 111,481 |  |  | $ | 73,356 |  |  |  | 52.0 | %
Direct operating costs |  |  | 101,628 |  |  |  | 69,050 |  |  |  | 47.2 | %
Adjusted gross margin (1) |  |  | 9,853 |  |  |  | 4,306 |  |  |  | 128.8 | %
Restructuring expenses |  |  | — |  |  |  | 3,175 |  |  | NA |
Selling, general and administrative |  |  | 4,884 |  |  |  | 5,239 |  |  |  | (6.8 | )%
Depreciation, amortization and impairment |  |  | 40,270 |  |  |  | 36,504 |  |  |  | 10.3 | %
Operating loss |  | $ | (35,301 | ) |  | $ | (40,612 | ) |  |  | (13.1 | )%
Capital expenditures |  | $ | 8,591 |  |  | $ | 4,681 |  |  |  | 83.5 | %

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

Reduced demand for crude oil and refined products related to the COVID-19 pandemic, combined with production increases from OPEC+, led to a significant reduction in crude oil prices and demand for directional drilling services in 2020 and early 2021.

Directional drilling revenue and direct operating costs increased from 2020 primarily due to increased job activity. We averaged 30.1 jobs per day in 2021 as compared to 18.9 jobs per day for the comparable period in 2020. Additionally, a portion of the increase in direct operating costs relates to an inventory write-down of $4.0 million in 2021. Excluding the effects of this write-down, direct operating costs would have been approximately $97.6 million, an increase of 41.3% as compared to 2020. See Note 5 of Notes to Consolidated Financial Statements in Item 8 of this Report for additional information regarding the inventory write-down.

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Restructuring expenses were recognized in the second quarter of 2020 and were primarily attributable to severance and right-of-use asset abandonments. See Note 20 of Notes to Consolidated Financial Statements in Item 8 of this Report for additional information.

Depreciation, amortization and impairment increased as a result of the abandonment of an $11.4 million developed technology intangible asset and $2.5 million of directional drilling equipment in 2021. Excluding these charges, depreciation and amortization expense would have been $26.4 million, a 27.8% decline as compared to 2020. The decrease excluding impairments is due to lower cumulative capital expenditures in recent years, which reduced our depreciable asset base as depreciation, amortization and impairment outpaced capital expenditures between the periods.

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

|  | Year Ended December 31, |
Other Operations |  | 2021 |  |  | 2020 |  |  | % Change |
|  | (Dollars in thousands) |
Revenues |  | $ | 57,814 |  |  | $ | 45,656 |  |  |  | 26.6 | %
Direct operating costs |  |  | 40,911 |  |  |  | 41,790 |  |  |  | (2.1 | )%
Adjusted gross margin (1) |  |  | 16,903 |  |  |  | 3,866 |  |  |  | 337.2 | %
Restructuring expenses |  |  | — |  |  |  | 501 |  |  | NA |
Selling, general and administrative |  |  | 1,943 |  |  |  | 3,539 |  |  |  | (45.1 | )%
Depreciation, depletion, amortization and impairment |  |  | 24,865 |  |  |  | 41,511 |  |  |  | (40.1 | )%
Operating loss |  | $ | (9,905 | ) |  | $ | (41,685 | ) |  |  | (76.2 | )%
Capital expenditures |  | $ | 11,638 |  |  | $ | 12,378 |  |  |  | (6.0 | )%

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

Reduced demand for crude oil and refined products related to the COVID-19 pandemic, combined with production increases from OPEC+, led to a significant reduction in crude oil prices and demand for oilfield rental and other services in 2020 and early 2021.

Other operations revenue increased from 2020 primarily due to an $8.6 million increase in our oil and natural gas revenues as a result of favorable crude oil and natural gas market prices. Average WTI-Cushing prices in 2021 were $68.14 per barrel as compared to $39.16 per barrel in 2020. Because the increase in oil and natural gas revenues was driven by market pricing, we did not have a commensurate increase in direct operating costs for our oil and natural gas business. We also recognized a $4.7 million increase in revenue from our oilfield rentals business primarily due to an increase in our volume of services.

Other operations direct operating costs remained relatively flat despite the increase in revenues primarily due to the majority of the revenue increase being driven by market prices rather than incremental activity.

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

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

Depreciation, depletion, amortization and impairment decreased primarily due to an $11.2 million impairment related to certain of our oil and natural gas assets in 2020 as compared to a $1.3 million impairment of oil and natural gas assets in 2021. Excluding the impairment to our oil and natural gas properties in both years, the decrease in depreciation, depletion and amortization would have been $6.7 million, a 22.2% decrease. The impairment in 2020 reduced our depreciable base, which lowered depreciation in subsequent periods. Additionally, the decrease in depreciation, depletion, amortization and impairment was partially due to lower cumulative capital expenditures in recent years, which also reduced our depreciable asset base as depreciation, depletion, amortization and impairment outpaced capital expenditures between the periods.

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|  | Year Ended December 31, |
Corporate |  | 2021 |  |  | 2020 |  |  | % Change |
|  | (Dollars in thousands) |
Selling, general and administrative |  | $ | 73,495 |  |  | $ | 75,612 |  |  |  | (2.8 | )%
Merger and integration expenses |  | $ | 12,060 |  |  | $ | — |  |  | NA |
Restructuring expenses |  | $ | — |  |  | $ | 901 |  |  | NA |
Depreciation |  | $ | 5,859 |  |  | $ | 6,494 |  |  |  | (9.8 | )%
Other operating expenses (income), net |  |  |  |  |  |  |  |  |
Net gain on asset disposals |  | $ | (1,426 | ) |  | $ | (3,079 | ) |  |  | (53.7 | )%
Legal-related expenses and settlements, net of insurance reimbursements |  |  | 762 |  |  |  | 1,680 |  |  |  | (54.6 | )%
Research and development |  |  | 1,371 |  |  |  | 3,411 |  |  |  | (59.8 | )%
Other |  |  | 31 |  |  |  | 9,232 |  |  |  | (99.7 | )%
Other operating expense (income), net |  | $ | 738 |  |  | $ | 11,244 |  |  |  | (93.4 | )%
Credit loss expense |  | $ | (1,500 | ) |  | $ | 5,606 |  |  | NA |
Interest income |  | $ | 222 |  |  | $ | 1,254 |  |  |  | (82.3 | )%
Interest expense |  | $ | 41,978 |  |  | $ | 40,770 |  |  |  | 3.0 | %
Other income (expense) |  | $ | (275 | ) |  | $ | 756 |  |  | NA |
Capital expenditures |  | $ | 1,521 |  |  | $ | 1,707 |  |  |  | (10.9 | )%

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

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. See Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Report.

Restructuring expenses were recognized in 2020 and were primarily attributable to severance and right-of-use asset abandonments. See Note 20 of Notes to Consolidated Financial Statements in Item 8 of this Report.

Other operating expenses (income), net includes net gains associated with the disposal of assets. Accordingly, the related gains have been excluded from the results of specific segments. The majority of the net gain on asset disposals in 2021 reflect gains on disposals of buildings, land and drilling equipment, while the gain on asset disposals in 2020 related to disposals of drilling and pressure pumping equipment. Additionally, other operating expenses (income), net includes charges of $9.2 million in the second quarter of 2020 related to a 2017 capacity reservation agreement that required a cash deposit to increase our access to finer grades of sand for our pressure pumping business. As market prices for sand substantially decreased since 2017, we purchased lower cost sand outside of this capacity reservation contract and revalued the deposit at its expected realizable value. The deposit related to the capacity reservation agreement had no balance remaining subsequent to the charge recorded in the second quarter of 2020.

A provision for credit losses of $5.6 million was recognized in 2020 with respect to accounts receivable balances that were estimated to be uncollectible. During 2021, we reversed $1.5 million of our credit loss provision related to certain customers who had previously experienced a deterioration in credit quality. Since initially recording loss provisions for these receivables, we have collected portions of the accounts that were deemed uncollectible.

Interest expense increased slightly as compared to 2020. However, 2020 interest expense was favorably impacted by a gain on debt extinguishment of $3.6 million associated with the repurchase of portions of our 2028 Notes and 2029 Notes. Excluding the effects of the gain, interest expense would have decreased by $2.4 million, a 5.5% decrease. 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 will not incur interest expense related to the Term Loan Agreement in subsequent periods.

Comparison of the years ended December 31, 2020 and 2019

A discussion of our results of operations for the fiscal year ended December 31, 2020 compared to the fiscal year ended December 31, 2019 is included in Part II, Item 7— "Management's Discussion and Analysis of Financial Condition and Results of Operations" of our Annual Report on Form 10-K for the fiscal year ended December 31, 2020, filed with the SEC on February 9, 2021.

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Income Taxes

The effective tax rate decreased by approximately 5% to 8.7% for 2021 compared to 13.7% for 2020. The difference was primarily due to nondeductible goodwill impairment charges in 2020 impacting the effective tax rate and changes in valuation allowance positions between 2020 and 2021.

We continue to monitor income tax developments in the United States and other countries where we have legal entities. We will incorporate into our future financial statements the impacts, if any, of future regulations and additional authoritative guidance when finalized.

Liquidity and Capital Resources

During the second quarter of 2020, we implemented a restructuring plan to improve operating margins, achieve operational efficiencies and reduce indirect support costs. The restructuring included workforce reductions, changes to management structure and facility consolidations and closures. We recorded $38.3 million of charges associated with this plan in second quarter of 2020. We completed the restructuring plan during the third quarter of 2020 and did not incur additional expenses related to the plan. There were no restructuring charges in 2021.

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, 2021, we had approximately $148 million in working capital, including $118 million of cash and cash equivalents, and approximately $600 million available under our revolving credit facility.

We have an amended and restated credit agreement (the “Credit Agreement”), which is a committed senior unsecured revolving credit facility that permits aggregate borrowings of up to $600 million, including a letter of credit facility that, at any time outstanding, is limited to $150 million and a swing line facility that, at any time outstanding, is limited to $20 million. As of December 31, 2021, we had no borrowings outstanding under our revolving credit facility, and $0.1 million in letters of credit outstanding under the Credit Agreement and, as a result, had available borrowing capacity of approximately $600 million at that date. Of the revolving credit commitments, $50 million expires on March 27, 2024, and the remaining $550 million expires on March 27, 2025. Subject to customary conditions, we may request that the lenders’ aggregate commitments be increased by up to $300 million, not to exceed total commitments of $900 million. Additionally, we have the option, subject to certain conditions, to exercise one one-year extension of the maturity date.

Loans under the Credit Agreement bear interest by reference, at our election, to the LIBOR rate or base rate, as described in “Item 7A” below. If our credit rating is below investment grade at both Moody’s and S&P, we will become subject to a restricted payment covenant. The Credit Agreement also contains a financial covenant that requires our total debt to capitalization ratio, expressed as a percentage, not exceed 50%.

We also have a Reimbursement Agreement (the “Reimbursement Agreement”) with The Bank of Nova Scotia (“Scotiabank”), pursuant to which we may from time to time request that Scotiabank issue an unspecified amount of letters of credit. Under the terms of the Reimbursement Agreement, we will reimburse Scotiabank on demand for any amounts that Scotiabank has disbursed under any letters of credit. We are obligated to pay to Scotiabank interest on all amounts not paid by us on the date of demand or when otherwise due at the LIBOR rate plus 2.25% per annum.

Our outstanding debt at December 31, 2021 was $859 million and consisted of $510 million of 3.95% Senior Notes due 2028 (the “2028 Notes”), $349 million of 5.15% Senior Notes due 2029 (the “2029 Notes”). We were in compliance with all covenants at December 31, 2021.

For a full description of the Credit Agreement, the Reimbursement Agreement, the 2028 Notes and the 2029 Notes, see Note 9 of Notes to consolidated financial statements in Item 8 of this Report.

We had $71.5 million of outstanding letters of credit at December 31, 2021, which were comprised of $71.4 million outstanding under the Reimbursement Agreement and $0.1 million outstanding under the Credit Agreement. We maintain these letters of credit primarily for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under terms of the underlying insurance contracts. These letters of credit expire annually at various times during the year and are typically renewed. As of December 31, 2021, no amounts had been drawn under the letters of credit.

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Cash Requirements

We believe our curr ent liquidity, together with cash expected to be generated from operations, should provide us with sufficient ability to fund our current plans to maintain and make improvements to our existing equipment, service our debt and pay cash dividends for at least the next 12 months.

If we pursue opportunities for growth that require capital, we believe we would be able to satisfy these needs through a combination of working capital, cash flows from operating activities, borrowing capacity under our revolving credit facility or additional debt or equity financing. However, there can be no assurance that such capital will be available on reasonable terms, if at all.

A portion of our capital expenditures can be adjusted and managed by us to match market demand and activity levels. Based on our current outlook for activity, we expect our capital expenditures for 2022 to be approximately $350 million. The majority of these expenditures are expected to be used for normal, recurring items necessary to support our business.

We anticipate $9.7 million of expenditures in 2022 related to various contractual obligations such as certain purchase commitments and operating lease liabilities.

As of December 31, 2021, we had working capital of $148 million, including cash and cash equivalents of $118 million, compared to working capital of $204 million, including cash and cash equivalents of $225 million, at December 31, 2020.

During 2021, our sources of cash flow included:

•
$95.5 million from operating activities,
•
$42.0 million in proceeds, net of disposed cash, from the disposal of the Pioneer Production Services business,
•
$23.3 million in proceeds from the disposal of property and equipment.

During 2021, we used $29.4 million, net of acquired cash, for the acquisition of Pioneer, $15.6 million to pay dividends on our common stock, $50 million to repay borrowings under our Term Loan Agreement and $166 million:

•
to make capital expenditures for the betterment and refurbishment of drilling and pressure pumping equipment and, to a much lesser extent, equipment for our other businesses,
•
to acquire and procure equipment to support our contract drilling, pressure pumping, directional drilling, oilfield rentals and manufacturing operations, and
•
to fund investments in oil and natural gas properties on a non-operating working interest basis.

We paid cash dividends during the year ended December 31, 2021 as follows:

|  | Per Share |  |  | Total |
|  |  |  |  | (in thousands) |
Paid on March 18, 2021 |  | $ | 0.02 |  |  | $ | 3,754 |
Paid on June 17, 2021 |  |  | 0.02 |  |  |  | 3,769 |
Paid on September 16, 2021 |  |  | 0.02 |  |  |  | 3,780 |
Paid on December 16, 2021 |  |  | 0.02 |  |  |  | 4,302 |
Total cash dividends |  | $ | 0.08 |  |  | $ | 15,605 |

On February 9, 2022, our Board of Directors approved a cash dividend on our common stock in the amount of $0.04 per share to be paid on March 17, 2022 to holders of record as of March 3, 2022. The amount and timing of all future dividend payments, if any, are subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of our debt agreements and other factors. Our Board of Directors may, without advance notice, reduce or suspend our dividend in order to improve our financial flexibility and best position our company for long-term success. There can be no assurance that we will pay a dividend in the future.

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

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On September 6, 2013, our Board of Directors approved a stock buyback program that authorized purchases of up to $200 million of our common stock in open market or privately negotiated transactions. The authorized repurchases under this program were subsequently increased in July 2018 and February 2019, and on July 24, 2019, our Board of Directors approved another increase of the authorization under the stock buyback program to allow for $250 million of future share repurchases. All purchases executed to date have been through open market transactions. Purchases under the program are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Purchases may be made at any time without prior notice. There is no expiration date associated with the buyback program. As of December 31, 2021, we had remaining authorization to purchase approximately $130 million of our outstanding common stock under the stock buyback program. Shares of stock purchased under the buyback program are held as treasury shares.

We acquired shares of stock from employees during 2021, 2020 and 2019 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”), 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, 2021, 2020 and 2019 were as follows (dollars in thousands):

|  | 2021 |  |  | 2020 |  |  | 2019 |
|  | Shares |  |  | Cost |  |  | Shares |  |  | Cost |  |  | Shares |  |  | Cost |
Treasury shares at beginning of period |  |  | 83,402,322 |  |  | $ | 1,366,313 |  |  |  | 77,336,387 |  |  | $ | 1,345,134 |  |  |  | 53,701,096 |  |  | $ | 1,080,448 |
Purchases pursuant to stock buyback program |  |  | — |  |  |  | — |  |  |  | 5,826,266 |  |  |  | 20,000 |  |  |  | 22,566,331 |  |  |  | 250,109 |
Acquisitions pursuant to long-term incentive plan |  |  | 451,196 |  |  |  | 3,727 |  |  |  | 239,669 |  |  |  | 1,179 |  |  |  | 1,037,947 |  |  |  | 14,205 |
Purchases in connection with Pioneer acquisition |  |  | 275,477 |  |  |  | 2,601 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Other |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 31,013 |  |  |  | 372 |
Treasury shares at end of period |  |  | 84,128,995 |  |  | $ | 1,372,641 |  |  |  | 83,402,322 |  |  | $ | 1,366,313 |  |  |  | 77,336,387 |  |  | $ | 1,345,134 |

As of December 31, 2021, we had unrecognized compensation costs of $17.3 million and $6.6 million related to our unvested restricted stock units and our unvested Performance Units, respectively. The weighted-average remaining vesting periods for these awards were 1.66 years and 1.44 years, respectively as of December 31, 2021. 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, 2021, we had commitments to purchase major equipment totaling approximately $99.0 million for our drilling, pressure pumping, directional drilling and oilfield rentals businesses.

Our pressure pumping business has entered into agreements to purchase minimum quantities of proppants and chemicals from certain vendors. The remaining terms of the agreements are less than one year. In the event the required minimum quantities are not purchased during any contract year, we could be required to make a liquidated damages payment to the respective vendor for any shortfall. In 2017, we entered into a capacity reservation agreement that required a cash deposit to increase our access to finer grades of sand for our pressure pumping business. As market prices for sand substantially decreased since 2017, we purchased lower cost sand outside of this capacity reservation contract and recorded a charge of $9.2 million and $12.7 million in the second quarters of 2020 and 2019, respectively, to revalue the deposit to its expected realizable value. There is no value assigned to the capacity reservation contract subsequent to the charge recorded in the second quarter of 2020.

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, 2021.

Operating lease liabilities totaled $25.0 million at December 31, 2021. 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, 2021.

Trading and Investing — We have not engaged in trading activities that include high-risk securities, such as derivatives and non-exchange traded contracts. We invest cash primarily in highly liquid, short-term investments such as overnight deposits and money market accounts.

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Critical Accounting Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“U.S. 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.

Allowance for credit losses — We utilize an accounts receivable aging schedule and historical credit loss information to estimate expected credit losses. We evaluate our accounts receivable periodically through review of historical collection experience, current aging status of the customer accounts, financial condition of our customers, and the overall economic environment of the oil and gas industry. Any customers that have experienced a deterioration in credit quality are removed from the pool and evaluated individually. This process involves judgment and estimation. Accordingly, our results of operations can be affected by adjustments to the allowance due to actual write-offs that differ from estimated amounts. During 2021, we updated our expected credit loss rates for historical credit loss information associated with customers with accounts receivable acquired in the Pioneer acquisition. In applying our methodology of estimating credit losses, we determined no material changes to our credit loss rates. See Note 4 of Notes to Consolidated Financial Statements included as a part of Item 8 of this Report.

Depreciation and amortization — 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. See Note 1 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 market day rates, direct operating costs, rig utilization percentages, expectations regarding the amount of future capital and operating costs, 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.

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”). In connection with this review, assets are grouped at the lowest level at which identifiable cash flows are largely independent of other asset groupings. We estimate future cash flows over the life of the respective assets or asset groupings in our assessment of impairment. These estimates of cash flows are based on historical cyclical trends in the industry as well as our expectations regarding the continuation of these trends in the future. If the carrying amount of the asset is not recoverable based on its estimated undiscounted cash flows expected to result from the use and eventual disposition, an impairment loss is recognized in an amount by which its carrying amount exceeds its estimated fair value. The inputs used to determine such fair value are primarily based upon internally developed cash flow models. Our cash flow models are based on a number of estimates regarding future operations that may be subject to significant variability, are sensitive to changes in market conditions, and are reasonably likely to change in the future. We determined no triggering events occurred in 2021. See Note 6 of Notes to Consolidated Financial Statements included as a part of Item 8 of this Report.

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

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

Our revenue, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas and expectations about future prices. For many years, oil and natural gas prices and markets have been extremely volatile. Prices are affected by many factors beyond our control. Please see “Risk Factors – 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” in Item 1A of this Report. Oil prices remain extremely volatile, as the closing price of oil (WTI-Cushing) reached a first quarter 2020 high of $63.27 per barrel on January 6, 2020, declined to negative $36.98 per barrel on April 20, 2020, and recovered to reach a 2021 high of $85.64 per barrel on October 26, 2021. In response to the rapid decline in commodity prices, E&P companies acted swiftly to reduce drilling and completion activity starting late in the first quarter of 2020. While oil prices have recovered in 2021, and demand for our services has improved since the commodity price decline in 2020, our average number of rigs operating remains well below the number of our available rigs, and a significant portion of our pressure pumping horsepower remains stacked. Oil prices averaged $77.45 per barrel in the fourth quarter of 2021.

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

Impact of Inflation

A s previously disclosed within our Quarterly Reports on Form 10-Q for the periods ended June 30, 2021 and September 30, 2021, due to improving activity levels and increasing tightness in the overall labor market, we have seen general oilfield cost inflation across our segments during 2021, including increases in the cost of labor, services and supplies. This inflation, combined with the increasing challenge of attracting employees to the industry, is increasing the complexity of reactivating equipment. We believe this challenge, combined with the increasing market tightness for premium drilling and completion services, will support higher pricing for our services in 2022. However, to date, this general inflationary trend has not had a material effect on our operating margins as both revenues and costs are impacted in tandem.

Recently Issued Accounting Standards

For a discussion of recently issued accounting standards, see Note 1 of Notes to Consolidated Financial Statements included as a part of Item 8 of this Report.

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Non-GAAP Measurements

Adjusted EBITDA

A djusted earnings before interest, taxes, depreciation and amortization (“Adjusted EBITDA”) is not defined by U.S. GAAP. We define Adjusted EBITDA as loss from continuing operations plus income tax benefit, net interest expense, and depreciation, depletion, amortization and impairment expense (including impairment of goodwill). We present Adjusted EBITDA because we believe it provides to both management and investors additional information with respect to the performance of our fundamental business activities and a comparison of the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from 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 U.S. GAAP measure of loss from continuing operations. Our computations of Adjusted EBITDA may not be the same as other similarly titled measures of other companies. Set forth below is a reconciliation of the non-U.S. GAAP financial measure of Adjusted EBITDA to the U.S. GAAP financial measure of loss from continuing operations.

|  | Year Ended December 31, |
|  | 2021 |  |  | 2020 |  |  | 2019 |
|  | (in thousands) |
Loss from continuing operations |  | $ | (657,079 | ) |  | $ | (803,692 | ) |  | $ | (425,703 | )
Income tax benefit |  |  | (62,702 | ) |  |  | (127,326 | ) |  |  | (104,675 | )
Net interest expense |  |  | 41,756 |  |  |  | 39,516 |  |  |  | 69,191 |
Depreciation, depletion, amortization and impairment |  |  | 849,178 |  |  |  | 670,910 |  |  |  | 1,003,873 |
Impairment of goodwill |  |  | — |  |  |  | 395,060 |  |  |  | 17,800 |
Adjusted EBITDA |  | $ | 171,153 |  |  | $ | 174,468 |  |  | $ | 560,486 |

Adjusted Gross Margin

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

| Contract Drilling |  |  | Pressure Pumping |  |  | Directional Drilling |  |  | Other Operations |
| (in thousands) |
For the year ended December 31, 2021 |  |  |  |  |  |  |  |  |  |  |
Operating revenues | $ | 664,030 |  |  | $ | 523,756 |  |  | $ | 111,481 |  |  | $ | 57,814 |
Less cost of sales |  | (463,456 | ) |  |  | (475,953 | ) |  |  | (101,628 | ) |  |  | (40,911 | )
Less depreciation, depletion, amortization and impairment |  | (618,879 | ) |  |  | (159,305 | ) |  |  | (40,270 | ) |  |  | (24,865 | )
GAAP gross margin |  | (418,305 | ) |  |  | (111,502 | ) |  |  | (30,417 | ) |  |  | (7,962 | )
Depreciation, depletion, amortization and impairment |  | 618,879 |  |  |  | 159,305 |  |  |  | 40,270 |  |  |  | 24,865 |
Adjusted gross margin | $ | 200,574 |  |  | $ | 47,803 |  |  | $ | 9,853 |  |  | $ | 16,903 |
For the year ended December 31, 2020 |  |  |  |  |  |  |  |  |  |  |
Operating revenues | $ | 669,126 |  |  | $ | 336,111 |  |  | $ | 73,356 |  |  | $ | 45,656 |
Less cost of sales |  | (380,822 | ) |  |  | (310,261 | ) |  |  | (69,050 | ) |  |  | (41,790 | )
Less depreciation, depletion, amortization and impairment |  | (433,771 | ) |  |  | (152,630 | ) |  |  | (36,504 | ) |  |  | (41,511 | )
GAAP gross margin |  | (145,467 | ) |  |  | (126,780 | ) |  |  | (32,198 | ) |  |  | (37,645 | )
Depreciation, depletion, amortization and impairment |  | 433,771 |  |  |  | 152,630 |  |  |  | 36,504 |  |  |  | 41,511 |
Adjusted gross margin | $ | 288,304 |  |  | $ | 25,850 |  |  | $ | 4,306 |  |  | $ | 3,866 |

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

As of December 31, 2021, we would have had exposure to interest rate market risk associated with any borrowings that we had under the Credit Agreement and amounts owed under the Reimbursement Agreement.

44

Loans under the Credit Agreement bear interest by reference, at our election, to the LIBOR rate or base rate. The applicable margin on LIBOR rate loans varies from 1.00% to 2.00% and the applicable margin on base rate loans varies from 0.00% to 1.00%, in each case determined based on our credit rating. As of December 31, 2021, the applicable margin on LIBOR rate loans was 1.75% and the applicable margin on base rate loans was 0.75%. As of December 31, 2021, we had no borrowings outstanding under our revolving credit facility. The interest rate on borrowings outstanding under our revolving credit facility is variable and adjusts at each interest payment date based on our election of LIBOR or the base rate.

Under the terms of the Reimbursement Agreement, we will reimburse Scotiabank on demand for any amounts that Scotiabank has disbursed under any letters of credit. We are obligated to pay Scotiabank interest on all amounts not paid by us on the date of demand or when otherwise due at the LIBOR rate plus 2.25% per annum. As of December 31, 2021, no amounts had been disbursed under any letters of credit.

The carrying values of cash and cash equivalents, trade receivables and accounts payable approximate fair value due to the short-term maturity of these items.

Item 8. Financial Statements and Supplementary Data.

Financial Statements are filed as a part of this Report at the end of Part IV hereof beginning at page F-1, Index to Consolidated Financial Statements, and are incorporated herein by this reference.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A. Controls and Procedures.

Disclosure Controls and Procedures:

Under the supervision and with the participation of our management, including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), we conducted an evaluation of the effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Exchange Act, as of the end of the period covered by this Report. Based on this evaluation, our CEO and CFO concluded that, as of December 31, 2021, our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and is accumulated and reported to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

Management’s Report on Internal Control over Financial Reporting:

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including our CEO and CFO, we carried out an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2021, 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, 2021.

The acquired businesses associated with Pioneer Energy Services Corp. (“Pioneer”), were excluded from our evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2021. These subsidiaries were excluded from the scope of our review due to the fact that the acquisition closed in the fourth quarter of 2021, at which time we began integrating the acquired business into our existing internal controls over financial reporting. Under guidelines established by the SEC, companies are permitted to exclude acquisitions from their assessment of internal control over financial reporting during the first year of an acquisition while integrating the acquired company. As a result of these integration activities, certain controls will be evaluated and may be changed. The acquired businesses represented approximately three percent of our consolidated revenues for the year ended December 31, 2021 and approximately 10% of our consolidated total assets as of December 31, 2021.

The effectiveness of our internal control over financial reporting as of December 31, 2021 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.

45

Changes in Internal Control over Financial Reporting:

Except as noted above, there were no changes to our internal control over financial reporting during the most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information.

None.

46

PART III

Certain information required by Part III is omitted from this Report because we expect to file a definitive proxy statement (the “Proxy Statement”) pursuant to Regulation 14A of the Securities Exchange Act of 1934 no later than 120 days after the end of the fiscal year covered by this Report and certain information included therein is incorporated herein by reference.

Item 10. Directors, Executive Officers and Corporate Governance.

The information required by this Item is incorporated herein by reference to the Proxy Statement.

We have adopted a Code of Business Conduct and Ethics for Senior Financial Executives, which covers, among others, our principal executive officer and principal financial and accounting officer. The text of this code is located on our website under “Corporate Governance.” Our Internet address is www.patenergy.com. We intend to disclose any amendments to or waivers from this code on our website within four business days following the date of the amendment or waiver.

Item 11. Executive Compensation.

The information required by this Item is incorporated herein by reference to the Proxy Statement.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The information required by this Item is incorporated herein by reference to the Proxy Statement.

Item 13. Certain Relationships and Related Transactions, and Director Independence.

The information required by this Item is incorporated herein by reference to the Proxy Statement.

Item 14. Principal Accounting Fees and Services.

The information required by this Item is incorporated herein by reference to the Proxy Statement.

47

PART IV

Item 15. Exhibits and Financial Statement Schedule.

(a)(1) Financial Statements

See Index to Consolidated Financial Statements on page F-1 of this Report.

(a)(2) Report of Independent Registered Public Accounting Firm

The report of our independent registered public accounting firm (PCAOB ID: 238) with respect to the above-referenced financial statements and their report on internal control over financial reporting are included on page F-2 of this Report.

(a)(3) Financial Statement Schedule

Schedule II — Valuation and qualifying accounts is filed herewith on page S-1.

All other financial statement schedules have been omitted because they are not applicable or the information required therein is included elsewhere in the financial statements or notes thereto.

(a)(3) Exhibits

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

2.1 |  | Agreement and Plan of Merger, dated July 5, 2021, among Patterson-UTI Energy, Inc., Crescent Merger Sub Inc., Crescent Ranch Second Merger Sub LLC, and Pioneer Energy Services Corp. (incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K filed on July 6, 2021).
2.2 |  | Amendment No. 1 to Agreement and Plan of Merger, dated September 13, 2021, among Patterson-UTI Energy, Inc., Crescent Merger Sub Inc., Crescent Ranch Second Merger Sub LLC, and Pioneer Energy Services Corp. (incorporated by reference to Exhibit 2.2 to our Current Report on Form 8-K filed on October 4, 2021).
3.1 |  | Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.1 to our Quarterly Report on Form 10-Q and incorporated herein by reference).
3.2 |  | Certificate of Amendment to the Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.2 to our Quarterly Report on Form 10-Q and incorporated herein by reference).
3.3 |  | Certificate of Elimination with respect to Series A Participating Preferred Stock (filed October 27, 2011 as Exhibit 3.1 to our Current Report on Form 8-K and incorporated herein by reference).
3.4 |  | Certificate of Amendment to Restated Certificate of Incorporation, as amended (filed July 30, 2018 as Exhibit 3.4 to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2018 and incorporated herein by reference).
3.5 |  | Fourth Amended and Restated Bylaws (filed February 12, 2019 as Exhibit 3.1 to our Current Report on Form 8-K and incorporated herein by reference).
3.6 |  | Certificate of Designation of the Series A Junior Participating Preferred Stock of Patterson-UTI Energy, Inc., dated April 22, 2020 (filed April 23, 2020 as Exhibit 3.1 to our Current Report on Form 8-K and incorporated herein by reference).
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).

48

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 |  | Stockholder Rights Agreement, dated as of April 22, 2020, by and between Patterson-UTI Energy, Inc. and Continental Stock Transfer & Trust Company, as rights agent (which includes the Form of Rights Certificate as Exhibit B thereto) (filed April 23, 2020 as Exhibit 4.1 to our Current Report on Form 8-K and incorporated herein by reference).
4.10 |  | First Amendment to Stockholder Rights Agreement, dated as of July 22, 2020, by and between Patterson-UTI Energy, Inc. and Continental Stock Transfer & Trust Company, as rights agent (filed July 23, 2020 as Exhibit 4.1 to our Current Report on Form 8-K and incorporated herein by reference).
10.1 |  | Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, including Form of Executive Officer Restricted Stock Award Agreement, Form of Executive Officer Stock Option Agreement, Form of Non-Employee Director Restricted Stock Award Agreement and Form of Non-Employee Director Stock Option Agreement (filed June 21, 2005 as Exhibit 10.1 to our Current Report on Form 8-K and incorporated herein by reference).*
10.2 |  | First Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed June 6, 2008 as Exhibit 10.1 to our Current Report on Form 8-K and incorporated herein by reference).*
10.3 |  | Second Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed June 6, 2008 as Exhibit 10.2 to our Current Report on Form 8-K and incorporated herein by reference).*
10.4 |  | Third Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed April 27, 2010 as Exhibit 10.1 to our Current Report on Form 8-K and incorporated herein by reference).*
10.5 |  | Fourth Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed April 27, 2010 as Exhibit 10.2 to our Current Report on Form 8-K and incorporated herein by reference).*
10.6 |  | Fifth Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed August 2, 2010 as Exhibit 10.4 to our Quarterly Report on Form 10-Q and incorporated herein by reference).*
10.7 |  | Patterson-UTI Energy, Inc. Omnibus Incentive Plan (filed April 21, 2017 as Exhibit 4.4 to our Registration Statement on Form S-8 and incorporated herein by reference).*
10.8 |  | Patterson-UTI Energy, Inc. 2014 Long-Term Incentive Plan (filed April 21, 2014 as Exhibit 10.1 to our Current Report on Form 8-K and incorporated herein by reference).*
10.9 |  | Patterson-UTI Energy, Inc. 2014 Long-Term Incentive Plan (as amended and restated effective June 29, 2017) (filed June 30, 2017 as Exhibit 10.1 to our Current Report on Form 8-K and incorporated herein by reference).*
10.10 |  | 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).*
10.11 |  | Patterson-UTI Energy, Inc. 2021 Long-Term Incentive Plan (incorporated by reference to Annex A of our Definitive Proxy Statement on Schedule 14A, filed on April 12, 2021).*
10.12 |  | 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).*

49

10.13 |  | 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).*
10.14 |  | 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).*
10.15 |  | Form of Non-Employee Director Restricted Stock Unit Award Agreement (filed April 28, 2020 as Exhibit 10.1 to our Quarterly Report on Form 10-Q and incorporated herein by reference).*
10.16 |  | 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).*
10.17 |  | 2020 Phantom Unit Award Agreement, dated May 11, 2020, by and between Patterson-UTI Energy, Inc. and William A. Hendricks, Jr. (filed July 28, 2020 as Exhibit 10.2 to our Quarterly Report on Form 10-Q and incorporated herein by reference).*
10.18 |  | Amendment No. 1 to Performance Share Award Agreement, dated May 11, 2020, by and between Patterson-UTI Energy, Inc. and William A. Hendricks, Jr. (filed July 28, 2020 as Exhibit 10.2 to our Quarterly Report on Form 10-Q and incorporated herein by reference).*
10.19 |  | 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).*
10.20 |  | Employment Agreement, effective as of January 1, 2017, by and between Patterson-UTI Drilling Company LLC and James M. Holcomb (filed January 17, 2017 as Exhibit 10.1 to our Current Report on Form 8-K and incorporated herein by reference).*
10.21 |  | First Amendment to Employment Agreement, effective as April 9, 2021, by and between Patterson-UTI Energy, Inc. and James M. Holcomb (filed August 3, 2021 as Exhibit 10.7 to our Quarterly Report on Form 10-Q and incorporated herein by reference).*
10.22 |  | 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).*
10.23 |  | 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).*
10.24 |  | 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).*
10.25 |  | 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).*
10.26 |  | 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).*
10.27 |  | 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).*
10.28 |  | Form of Indemnification Agreement entered into by Patterson-UTI Energy, Inc. with each of Kenneth N. Berns, Curtis W. Huff, Terry H. Hunt, Seth D. Wexler, William Andrew Hendricks, Jr., Michael W. Conlon, Tiffany J. Thom, James M. Holcomb, C. Andrew Smith and Janeen S. Judah (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).*

50

10.29 |  | 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).*
10.30 |  | 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).*
10.31 |  | 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).
10.32 |  | 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).
10.33 |  | 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).
10.34 |  | 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).
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.++
101.INS |  | Inline XBRL Instance Document – the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.+
101.SCH |  | Inline XBRL Taxonomy Extension Schema Document+
101.CAL |  | Inline XBRL Taxonomy Extension Calculation Linkbase Document+
101.DEF |  | Inline XBRL Taxonomy Extension Definition Linkbase Document+
101.LAB |  | Inline XBRL Taxonomy Extension Label Linkbase Document+
101.PRE |  | Inline XBRL Taxonomy Extension Presentation Linkbase Document+
104 |  | Cover Page Interactive Data File (formatted as inline XBRL with applicable taxonomy extension information contained in Exhibits 101).

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

+ Filed herewith.

++ Furnished herewith.

51

Item 16. Form 10-K Summary

None.

52

|  | Page
Report of Independent Registered Public Accounting Firm |  | F-2
Consolidated Financial Statements: |  |
Consolidated Balance Sheets as of December 31, 2021 and 2020 |  | F-4
Consolidated Statements of Operations for the years ended December 31, 2021, 2020 and 2019 |  | F-5
Consolidated Statements of Comprehensive Loss for the years ended December 31, 2021, 2020 and 2019 |  | F-6
Consolidated Statements of Changes in Stockholders’ Equity for the years ended December 31, 2021, 2020 and 2019 |  | F-7
Consolidated Statements of Cash Flows for the years ended December 31, 2021, 2020 and 2019 |  | F-8
Notes to Consolidated Financial Statements |  | F-9

F-1

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Patterson-UTI Energy, Inc.

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of Patterson-UTI Energy, Inc. and its subsidiaries (the “Company”) as of December 31, 2021 and 2020, and the related consolidated statements of operations, of comprehensive loss, of changes in stockholders’ equity and of cash flows for each of the three years in the period ended December 31, 2021, including the related notes and schedule of valuation and qualifying accounts for each of the three years in the period ended December 31, 2021 appearing under Item 15(a)(2) (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2021, 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, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021 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, 2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

Basis for Opinions

The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As described in Management’s Report on Internal Control over Financial Reporting, management has excluded Pioneer Energy Services Corp. (“Pioneer”) from its assessment of internal control over financial reporting as of December 31, 2021, because it was acquired by the Company in a purchase business combination during 2021. We have also excluded Pioneer from our audit of internal control over financial reporting. Pioneer is a wholly owned subsidiary whose total assets and total revenues excluded from management’s assessment and our audit of internal control over financial reporting represent 10% and approximately 3%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2021.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

F-2

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Critical Audit Matters

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Acquisition of Pioneer – Valuation of the United States Drilling Rigs

As described in Notes 1 and 2 to the consolidated financial statements, on October 1, 2021, the Company completed the acquisition of Pioneer by acquiring 100% of its equity interests for total consideration transferred of approximately $278 million. The Pioneer acquisition resulted in $215 million of property and equipment being recorded, of which a significant portion relates to 17 AC drilling rigs in the United States. 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. A discounted cash flow model was used by a third-party specialist in determining the fair value of the property and equipment and intangible assets. 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 market day rates, direct operating costs, rig utilization percentages, expectations regarding the amount of future capital and operating costs, and discount rates.

The principal considerations for our determination that performing procedures relating to the valuation of the United States drilling rigs acquired in the Pioneer acquisition is a critical audit matter are (i) the significant judgment by management when determining the fair value of the United States drilling rigs, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions used in the valuation related to the market day rates and 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 United States drilling rigs and controls over the determination of significant assumptions related to the market day rates and discount rate. These procedures also included, among others (i) reading the purchase agreement and (ii) testing management’s process for determining the fair value of the United States drilling rigs. Testing management’s process included evaluating the appropriateness of the discounted cash flow model, testing the completeness and accuracy of data provided by management, and evaluating the reasonableness of significant assumptions related to the market day rates and discount rate. Evaluating the reasonableness of the market day rates involved considering the consistency with external market and industry data and the past performance of the acquired business. Professionals with specialized skill and knowledge were used to assist in evaluating the appropriateness of the discounted cash flow model and in evaluating the reasonableness of the discount rate significant assumption.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 16, 2022

We have served as the Company’s auditor since 1993.

F-3

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

C ONSOLIDATED BALANCE SHEETS

|  | December 31, |
|  | 2021 |  |  | 2020 |
|  | (In thousands, except share data) |
ASSETS |  |  |  |  |  |
Current assets: |  |  |  |  |  |
Cash and cash equivalents |  | $ | 117,524 |  |  | $ | 224,915 |
Accounts receivable, net of allowance for credit losses of $8,493 and $10,842 at December 31, 2021 and 2020, respectively |  |  | 356,083 |  |  |  | 160,214 |
Federal and state income taxes receivable |  |  | 67 |  |  |  | 4,428 |
Inventory |  |  | 42,359 |  |  |  | 33,085 |
Other |  |  | 67,620 |  |  |  | 55,314 |
Total current assets |  |  | 583,653 |  |  |  | 477,956 |
Property and equipment, net |  |  | 2,331,755 |  |  |  | 2,761,041 |
Right of use asset |  |  | 19,024 |  |  |  | 16,850 |
Intangible assets |  |  | 7,537 |  |  |  | 30,087 |
Deposits on equipment purchases |  |  | 849 |  |  |  | 1,716 |
Other |  |  | 11,055 |  |  |  | 11,419 |
Deferred tax assets, net |  |  | 3,975 |  |  |  | — |
Total assets |  | $ | 2,957,848 |  |  | $ | 3,299,069 |
LIABILITIES AND STOCKHOLDERS’ EQUITY |  |  |  |  |  |
Current liabilities: |  |  |  |  |  |
Accounts payable |  | $ | 190,219 |  |  | $ | 91,023 |
Federal and state income taxes payable |  |  | 232 |  |  |  | — |
Accrued liabilities |  |  | 238,511 |  |  |  | 175,603 |
Lease liability |  |  | 6,891 |  |  |  | 7,096 |
Total current liabilities |  |  | 435,853 |  |  |  | 273,722 |
Long-term lease liability |  |  | 18,108 |  |  |  | 19,118 |
Long-term debt, net of debt discount and issuance costs of $6,432 and $7,271 at December 31, 2021 and 2020, respectively |  |  | 852,323 |  |  |  | 901,484 |
Deferred tax liabilities, net |  |  | 29,234 |  |  |  | 77,676 |
Other |  |  | 12,843 |  |  |  | 11,010 |
Total liabilities |  |  | 1,348,361 |  |  |  | 1,283,010 |
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 400,000,000 shares with 299,268,967 and 271,028,688 issued and 215,139,972 and 187,626,366 outstanding at December 31, 2021 and 2020, respectively |  |  | 2,993 |  |  |  | 2,710 |
Additional paid-in capital |  |  | 3,171,536 |  |  |  | 2,902,236 |
Retained earnings (deficit) |  |  | (198,316 | ) |  |  | 472,014 |
Accumulated other comprehensive income |  |  | 5,915 |  |  |  | 5,412 |
Treasury stock, at cost, 84,128,995 shares and 83,402,322 shares at December 31, 2021 and 2020, respectively |  |  | (1,372,641 | ) |  |  | (1,366,313 | )
Total stockholders’ equity |  |  | 1,609,487 |  |  |  | 2,016,059 |
Total liabilities and stockholders’ equity |  | $ | 2,957,848 |  |  | $ | 3,299,069 |

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

F-4

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEME NTS OF OPERATIONS

|  | Year Ended December 31, |
|  | 2021 |  |  | 2020 |  |  | 2019 |
|  | (In thousands, except per share data) |
Operating revenues: |  |  |  |  |  |  |  |  |
Contract drilling |  | $ | 664,030 |  |  | $ | 669,126 |  |  | $ | 1,308,350 |
Pressure pumping |  |  | 523,756 |  |  |  | 336,111 |  |  |  | 868,694 |
Directional drilling |  |  | 111,481 |  |  |  | 73,356 |  |  |  | 188,786 |
Other |  |  | 57,814 |  |  |  | 45,656 |  |  |  | 104,855 |
Total operating revenues |  |  | 1,357,081 |  |  |  | 1,124,249 |  |  |  | 2,470,685 |
Operating costs and expenses: |  |  |  |  |  |  |  |  |
Contract drilling |  |  | 463,456 |  |  |  | 380,822 |  |  |  | 785,355 |
Pressure pumping |  |  | 475,953 |  |  |  | 310,261 |  |  |  | 724,788 |
Directional drilling |  |  | 101,628 |  |  |  | 69,050 |  |  |  | 178,645 |
Other |  |  | 40,911 |  |  |  | 41,790 |  |  |  | 84,909 |
Depreciation, depletion, amortization and impairment |  |  | 849,178 |  |  |  | 670,910 |  |  |  | 1,003,873 |
Impairment of goodwill |  |  | — |  |  |  | 395,060 |  |  |  | 17,800 |
Selling, general and administrative |  |  | 92,382 |  |  |  | 97,611 |  |  |  | 133,513 |
Credit loss expense |  |  | (1,500 | ) |  |  | 5,606 |  |  |  | 5,683 |
Merger and integration expenses |  |  | 12,060 |  |  |  | — |  |  |  | — |
Restructuring expenses |  |  | — |  |  |  | 38,338 |  |  |  | — |
Other operating expenses (income), net |  |  | 763 |  |  |  | 7,059 |  |  |  | (2,305 | )
Total operating costs and expenses |  |  | 2,034,831 |  |  |  | 2,016,507 |  |  |  | 2,932,261 |
Operating loss |  |  | (677,750 | ) |  |  | (892,258 | ) |  |  | (461,576 | )
Other income (expense): |  |  |  |  |  |  |  |  |
Interest income |  |  | 222 |  |  |  | 1,254 |  |  |  | 6,013 |
Interest expense, net of amount capitalized |  |  | (41,978 | ) |  |  | (40,770 | ) |  |  | (75,204 | )
Other |  |  | (275 | ) |  |  | 756 |  |  |  | 389 |
Total other expense |  |  | (42,031 | ) |  |  | (38,760 | ) |  |  | (68,802 | )
Loss from continuing operations before income taxes |  |  | (719,781 | ) |  |  | (931,018 | ) |  |  | (530,378 | )
Income tax benefit |  |  | (62,702 | ) |  |  | (127,326 | ) |  |  | (104,675 | )
Loss from continuing operations |  |  | (657,079 | ) |  |  | (803,692 | ) |  |  | (425,703 | )
Income from discontinued operations, net of tax |  |  | 2,534 |  |  |  | — |  |  |  | — |
Net loss |  | $ | (654,545 | ) |  | $ | (803,692 | ) |  | $ | (425,703 | )
Net loss per common share - basic: |  |  |  |  |  |  |  |  |
Continuing operations |  | $ | (3.37 | ) |  | $ | (4.27 | ) |  | $ | (2.10 | )
Discontinued operations |  | $ | 0.01 |  |  | $ | — |  |  | $ | — |
Net loss - basic |  | $ | (3.36 | ) |  | $ | (4.27 | ) |  | $ | (2.10 | )
Net loss per common share - diluted: |  |  |  |  |  |  |  |  |
Continuing operations |  | $ | (3.37 | ) |  | $ | (4.27 | ) |  | $ | (2.10 | )
Discontinued operations |  | $ | 0.01 |  |  | $ | — |  |  | $ | — |
Net loss - diluted |  | $ | (3.36 | ) |  | $ | (4.27 | ) |  | $ | (2.10 | )
Weighted average number of common shares outstanding: |  |  |  |  |  |  |  |  |
Basic |  |  | 195,021 |  |  |  | 188,013 |  |  |  | 203,039 |
Diluted |  |  | 195,021 |  |  |  | 188,013 |  |  |  | 203,039 |

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

F-5

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

C ONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

|  | Year Ended December 31, |
|  | 2021 |  |  | 2020 |  |  | 2019 |
|  | (In thousands) |
Net loss |  | $ | (654,545 | ) |  | $ | (803,692 | ) |  | $ | (425,703 | )
Other comprehensive loss, net of taxes of $0 for 2021, $0 for 2020 and $0 for 2019: |  |  |  |  |  |  |  |  |
Foreign currency translation adjustment |  |  | 503 |  |  |  | (66 | ) |  |  | 2,991 |
Total comprehensive loss |  | $ | (654,042 | ) |  | $ | (803,758 | ) |  | $ | (422,712 | )

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

F-6

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

C ONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

|  |  |  |  |  |  |  |  |  |  |  |  | Accumulated |  |  |  |  |  |  |
| Common Stock |  |  | Additional |  |  |  |  |  | Other |  |  |  |  |  |  |
| Number of |  |  |  |  |  | Paid-in |  |  | Retained |  |  | Comprehensive |  |  | Treasury |  |  |  |
| Shares |  |  | Amount |  |  | Capital |  |  | Earnings (Deficit) |  |  | Income (Loss) |  |  | Stock |  |  | Total |
| (In thousands) |
Balance, December 31, 2018 |  | 267,316 |  |  | $ | 2,673 |  |  | $ | 2,827,154 |  |  | $ | 1,753,557 |  |  | $ | 2,487 |  |  | $ | (1,080,448 | ) |  | $ | 3,505,423 |
Net loss |  | — |  |  |  | — |  |  |  | — |  |  |  | (425,703 | ) |  |  | — |  |  |  | — |  |  |  | (425,703 | )
Foreign currency translation adjustment |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 2,991 |  |  |  | — |  |  |  | 2,991 |
Issuance of restricted stock |  | 185 |  |  |  | 2 |  |  |  | (2 | ) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Vesting of restricted stock units |  | 1,173 |  |  |  | 12 |  |  |  | (12 | ) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Forfeitures of restricted stock |  | (2 | ) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Exercise of stock options |  | 700 |  |  |  | 7 |  |  |  | 9,212 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 9,219 |
Stock-based compensation |  | — |  |  |  | — |  |  |  | 39,328 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 39,328 |
Payment of cash dividends |  | — |  |  |  | — |  |  |  | — |  |  |  | (32,428 | ) |  |  | — |  |  |  | — |  |  |  | (32,428 | )
Dividend equivalents |  | — |  |  |  | — |  |  |  | — |  |  |  | (524 | ) |  |  | — |  |  |  | — |  |  |  | (524 | )
Purchase of treasury stock |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (264,686 | ) |  |  | (264,686 | )
Balance, December 31, 2019 |  | 269,372 |  |  | $ | 2,694 |  |  | $ | 2,875,680 |  |  | $ | 1,294,902 |  |  | $ | 5,478 |  |  | $ | (1,345,134 | ) |  | $ | 2,833,620 |
Net loss |  | — |  |  |  | — |  |  |  | — |  |  |  | (803,692 | ) |  |  | — |  |  |  | — |  |  |  | (803,692 | )
Foreign currency translation adjustment |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (66 | ) |  |  | — |  |  |  | (66 | )
Issuance of restricted stock |  | 333 |  |  |  | 3 |  |  |  | (3 | ) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Vesting of restricted stock units |  | 1,324 |  |  |  | 13 |  |  |  | (13 | ) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Stock-based compensation |  | — |  |  |  | — |  |  |  | 26,572 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 26,572 |
Payment of cash dividends |  | — |  |  |  | — |  |  |  | — |  |  |  | (18,862 | ) |  |  | — |  |  |  | — |  |  |  | (18,862 | )
Dividend equivalents |  | — |  |  |  | — |  |  |  | — |  |  |  | (334 | ) |  |  | — |  |  |  | — |  |  |  | (334 | )
Purchase of treasury stock |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (21,179 | ) |  |  | (21,179 | )
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 |  | — |  |  |  | — |  |  |  | — |  |  |  | (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 |

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

F-7

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

C ONSOLIDATED STATEMENTS OF CASH FLOWS

|  | Year Ended December 31, |
|  | 2021 |  |  | 2020 |  |  | 2019 |
|  | (In thousands) |
Cash flows from operating activities: |  |  |  |  |  |  |  |  |
Net loss |  | $ | (654,545 | ) |  | $ | (803,692 | ) |  | $ | (425,703 | )
Adjustments to reconcile net loss to net cash provided by operating activities: |  |  |  |  |  |  |  |  |
Depreciation, depletion, amortization and impairment |  |  | 849,178 |  |  |  | 670,910 |  |  |  | 1,003,873 |
Impairment of goodwill |  |  | — |  |  |  | 395,060 |  |  |  | 17,800 |
Dry holes and abandonments |  |  | 178 |  |  |  | 1,285 |  |  |  | 109 |
Deferred income tax benefit |  |  | (62,980 | ) |  |  | (125,283 | ) |  |  | (103,202 | )
Stock-based compensation expense |  |  | 21,558 |  |  |  | 26,572 |  |  |  | 39,328 |
Net gain on asset disposals |  |  | (1,426 | ) |  |  | (3,079 | ) |  |  | (13,904 | )
Net gain on insurance reimbursement |  |  | — |  |  |  | (4,172 | ) |  |  | — |
Write-down of capacity reservation contract |  |  | — |  |  |  | 9,207 |  |  |  | 12,673 |
Credit loss expense |  |  | (1,500 | ) |  |  | 5,606 |  |  |  | 5,683 |
Restructuring expenses, non-cash |  |  | — |  |  |  | 25,067 |  |  |  | — |
(Gain) loss on early debt extinguishment |  |  | — |  |  |  | (3,596 | ) |  |  | 24,023 |
Amortization of debt discount and issuance costs |  |  | 839 |  |  |  | 912 |  |  |  | 937 |
Changes in operating assets and liabilities: |  |  |  |  |  |  |  |  |
Accounts receivable |  |  | (147,356 | ) |  |  | 173,862 |  |  |  | 213,588 |
Income taxes receivable/payable |  |  | 4,516 |  |  |  | 1,635 |  |  |  | (3,353 | )
Inventory and other assets |  |  | (5,850 | ) |  |  | 27,192 |  |  |  | 29,394 |
Accounts payable |  |  | 50,941 |  |  |  | (46,576 | ) |  |  | (77,281 | )
Accrued liabilities |  |  | 50,271 |  |  |  | (61,266 | ) |  |  | (18,623 | )
Other liabilities |  |  | (7,812 | ) |  |  | (10,786 | ) |  |  | (9,139 | )
Net cash used in operating activities of discontinued operations |  |  | (516 | ) |  |  | — |  |  |  | — |
Net cash provided by operating activities |  |  | 95,496 |  |  |  | 278,858 |  |  |  | 696,203 |
Cash flows from investing activities: |  |  |  |  |  |  |  |  |
Acquisitions, net of cash acquired |  |  | (29,358 | ) |  |  | — |  |  |  | (13 | )
Purchases of property and equipment |  |  | (166,320 | ) |  |  | (145,481 | ) |  |  | (347,512 | )
Proceeds from disposal of assets and insurance claims |  |  | 23,339 |  |  |  | 20,929 |  |  |  | 45,761 |
Other |  |  | (522 | ) |  |  | (424 | ) |  |  | — |
Net cash provided by investing activities of discontinued operations |  |  | 41,267 |  |  |  | — |  |  |  | — |
Net cash used in investing activities |  |  | (131,594 | ) |  |  | (124,976 | ) |  |  | (301,764 | )
Cash flows from financing activities: |  |  |  |  |  |  |  |  |
Purchases of treasury stock |  |  | (6,328 | ) |  |  | (21,179 | ) |  |  | (255,467 | )
Dividends paid |  |  | (15,605 | ) |  |  | (18,862 | ) |  |  | (32,428 | )
Proceeds from long-term debt |  |  | — |  |  |  | — |  |  |  | 496,969 |
Repayment of long-term debt |  |  | (50,000 | ) |  |  | (62,525 | ) |  |  | (673,443 | )
Debt issuance costs |  |  | — |  |  |  | (584 | ) |  |  | (852 | )
Net cash used in financing activities |  |  | (71,933 | ) |  |  | (103,150 | ) |  |  | (465,221 | )
Effect of foreign exchange rate changes on cash |  |  | 640 |  |  |  | (2 | ) |  |  | (62 | )
Net increase (decrease) in cash and cash equivalents |  |  | (107,391 | ) |  |  | 50,730 |  |  |  | (70,844 | )
Cash and cash equivalents at beginning of year |  |  | 224,915 |  |  |  | 174,185 |  |  |  | 245,029 |
Cash and cash equivalents at end of year |  | $ | 117,524 |  |  | $ | 224,915 |  |  | $ | 174,185 |
Supplemental disclosure of cash flow information: |  |  |  |  |  |  |  |  |
Net cash (paid) received during the year for: |  |  |  |  |  |  |  |  |
Interest, net of capitalized interest of $260 in 2021, $431 in 2020 and $732 in 2019 |  | $ | (40,464 | ) |  | $ | (43,368 | ) |  | $ | (76,870 | )
Income taxes |  |  | 4,196 |  |  |  | 3,709 |  |  |  | (1,452 | )
Non-cash investing and financing activities: |  |  |  |  |  |  |  |  |
Net increase (decrease) in payables for purchases of property and equipment |  | $ | 31,393 |  |  | $ | (30,241 | ) |  | $ | (40,857 | )
Issuance of common stock for business acquisitions |  |  | 248,025 |  |  |  | — |  |  |  | — |
Net decrease in deposits on equipment purchases |  |  | 867 |  |  |  | 6,350 |  |  |  | 3,974 |
Cashless exercise of stock options |  |  | — |  |  |  | — |  |  |  | 9,219 |

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

F-8

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

N OTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Description of Business and Summary of Significant Accounting Policies

A description of the business and basis of presentation follows:

Description of business — Patterson-UTI Energy, Inc., through its wholly-owned subsidiaries (collectively referred to herein as “we,” “us,” “our,” “ours” and like terms), is a Houston, Texas-based oilfield services company that primarily owns and operates in the United States one of the largest fleets of land-based drilling rigs and a large fleet of pressure pumping equipment. Our contract drilling business operates in the continental United States and internationally in Colombia and, from time to time, we pursue contract drilling opportunities in other select markets. Our pressure pumping business operates primarily in Texas and the Appalachian region. We also provide a comprehensive suite of directional drilling services in most major producing onshore oil and gas basins in the United States, and we provide services that improve the statistical accuracy of directional and horizontal wellbores. We have other operations through which we provide oilfield rental tools in select markets in the United States. We also service equipment for drilling contractors, and we provide electrical controls and automation to the energy, marine and mining industries, in North America and other select markets. In addition, we own and invest, as a non-operating, working interest owner, in oil and natural gas assets that are primarily located in Texas and New Mexico.

In the fourth quarter of 2021, we completed the acquisition of Pioneer Energy Services Corp. (“Pioneer”). Through the Pioneer acquisition, we acquired Pioneer’s 100% pad-capable drilling rig fleet consisting of 17 AC-powered rigs in the United States and eight SCR rigs in Colombia and production services assets consisting of 123 well servicing rigs and 72 wireline services units. The well servicing rigs and wireline services units, as discussed below, were subsequently divested. We believe the acquisition of Pioneer enhances our position as a leading provider of contract drilling services in the United States and expands our geographic footprint into Latin America, see Note 2.

On December 31, 2021, we completed the sale of the previously acquired well servicing rig business and wireline business (collectively, “Pioneer Production Services”), to Clearwell Dynamics, LLC (“Clearwell”). The sale price was $43.0 million in cash consideration, subject to customary purchase price adjustments at closing for cash and working capital. The results of operations of these businesses have been presented as a discontinued operation in these consolidated financial statements, s ee Note 2.

In the second quarter of 2020, we closed our Canadian drilling operations in response to our longer-term outlook for the western Canadian market. As a result of the closure, we recorded an impairment of $8.3 million.

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

The U.S. dollar is the functional currency for all of our operations except for our Canadian operations, which used the Canadian dollar as their functional currency. The effects of exchange rate changes are reflected in accumulated other comprehensive income, which is a separate component of stockholders’ equity.

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 (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure 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.

Revenue recognition — Revenues from our contract drilling, pressure pumping, directional drilling, oilfield rentals, equipment servicing and electrical control and automation activities are recognized as services are performed. All of the wells we drilled in 2021, 2020 and 2019 were drilled under daywork contracts. Revenue from sales of products are recognized upon customer acceptance. 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.

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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.

Leases — We have operating leases for operating locations, corporate offices and certain operating equipment. As of December 31, 2021, we did not have any finance leases.

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. We review the adequacy of our allowance for credit losses at least quarterly. 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 pressure pumping activities, materials used in our directional drilling and equipment servicing business and spare parts for our Colombia contract drilling business. Such inventories are stated at the lower of cost or net realizable value, with cost determined using the average cost method.

Other current assets — Other current assets includes reimbursement from our workers compensation insurance carrier for claims in excess of our deductible in the amount of $29.9 million and $36.1 million at December 31, 2021 and 2020, respectively.

Property and equipment — Property and equipment is carried at cost less accumulated depreciation. Depreciation is provided on the straight-line method over the estimated useful lives. The method of depreciation does not change whenever equipment becomes idle. The estimated useful lives, in years, are shown below:

|  | Useful Lives
Equipment |  | 1.25-15
Buildings |  | 15-20
Other |  | 3-12

Long-lived assets, including property and equipment, are evaluated for impairment when certain triggering events or changes in circumstances indicate that the carrying values may not be recoverable over their estimated remaining useful life.

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 the consolidated statement 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.

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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 $1.3 million, $11.2 million and $2.2 million was recorded for the years ended December 31, 2021, 2020 and 2019, respectively.

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, see Note 12.

As share-based compensation expense recognized in the consolidated statements of operations is based on awards ultimately expected to vest, it has been reduced for estimated forfeitures, based on historical experience. Forfeitures are estimated at the time of grant and revised in subsequent periods if actual forfeitures differ from those estimates.

Statement of cash flows — For purposes of reporting cash flows, cash and cash equivalents include cash on deposit and money market funds.

Recently Adopted Accounting Standards — In June 2016, the FASB issued an accounting standards update on measurement of credit losses on financial instruments. The new guidance requires us to measure all expected credit losses for financial instruments held at the reporting date based on historical experience, current conditions and reasonable and supportable forecasts. The new standard was effective for fiscal years beginning after December 15, 2019, including all interim periods within those years. We adopted ASU 2016-13 as of January 1, 2020. The adoption of this guidance and recognition of a loss allowance at an amount equal to expected credit losses for accounts receivable was not material and did not result in a transition adjustment to retained earnings. For more information regarding credit losses, see Note 4.

In August 2018, the FASB issued an accounting standards update to align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The capitalized implementation costs of a hosting arrangement that is a service contract will be expensed over the term of the hosting arrangement. The new standard was effective for fiscal years beginning after December 15, 2019, including all interim periods within those years. We adopted this new guidance on January 1, 2020 prospectively with respect to all implementation costs incurred after the date of adoption. There was no material impact on our consolidated financial statements.

In August 2018, the FASB issued an accounting standards update to eliminate certain disclosure requirements for fair value measurements for all entities, require public entities to disclose certain new information and modify certain disclosure requirements. The FASB developed the amendments to Topic 820 as part of its broader disclosure framework project, which aims to improve the effectiveness of disclosures in the notes to financial statements by focusing on requirements that clearly communicate the most important information to users of the financial statements. The new standard was effective for fiscal years beginning after December 15, 2019, including all interim periods within those years. We adopted this new guidance on January 1, 2020 and there was no material impact on our consolidated financial statements.

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

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

In October 2 021, the FASB issued an accounting standards update, which requires contract assets and contract liabilities (i.e., deferred revenue) acquired in a business combination to be recognized and measured by the acquirer on the acquisition date in accordance with ASC 606, Revenue from Contracts with Customers. Generally, this new guidance will result in the acquirer recognizing contract assets and contract liabilities at the same amounts recorded by the acquiree. Historically, such amounts were recognized by the acquirer at fair value in acquisition accounting. The amendments should be applied prospectively to acquisitions occurring on or after the effective date. The amendments in the update are effective for public business entities for fiscal years beginning after December 15, 2022, with early adoption permitted. We plan to adopt this new guidance on January 1, 2023, and we do not expect this new guidance will have a material impact on our consolidated financial statements.

During the third quarter of 2019, we identified and recorded out-of-period adjustments primarily related to the accounting for inventory in our directional drilling segment. We concluded that these adjustments were not material to the consolidated financial statements for any of the current or prior periods presented. The net adjustment is reflected as a $6.6 million increase to “Loss before income taxes” in the consolidated statements of operations for the year ended December 31, 2019.

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 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 |

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

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

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

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) |
Assets |  |  |  |  |
Trade name | $ | 907 |  |  |  | 5.00 |

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 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 intangibles and 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 |  |  | 2020 |
| (Unaudited) |
Revenues | $ | 1,464,351 |  |  | $ | 1,255,554 |
Net loss | $ | (666,032 | ) |  | $ | (809,996 | )

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.”

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Discontinued Operations

On December 31, 2021, we completed the sale of the previously acquired well servicing rig business and wireline business (collectively, “Pioneer Production Services”), to Clearwell. 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 have been presented as a discontinued operation in these consolidated financial statements.

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 |

In connection with the sale of our Pioneer Production Services business, we entered into a transition services agreement with Clearwell, pursuant to which we agreed to provide each other certain administrative and operational services on an interim, transitional basis through June 30, 2022.

3. Revenues

ASC Topic 606 Revenue from Contracts with Customers

Our contracts with customers include both long-term and short-term contracts. Services that primarily generate our earned revenue include the operating business segments of contract drilling, pressure pumping and directional drilling which comprise our reportable segments. We also derive revenues from our other operations, which include our operating business segments of oilfield rentals, equipment servicing, electrical controls and automation, and oil and natural gas working interests. For more information on our business segments, see Note 17.

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

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

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

Estimates of variable consideration are subject to change as facts and circumstances evolve. As such, we will evaluate our estimates of variable consideration that are subject to constraints throughout the contract period and revise estimates, if necessary, at the end of each reporting period.

We are a non-operating working interest owner of oil and natural gas properties primarily located in Texas and New Mexico. The ownership terms are outlined in joint operating agreements for each well between the operator of the well and the various interest owners, including us, who are considered non-operators of the well. We receive revenue each period for our working interest in the well during the period. The revenue received for the working interests from these oil and gas properties does not fall under the scope of ASC Topic 606, and therefore, is reported under ASC 932-323 Extractive Activities – Oil and Gas, Investments – Equity Method and Joint Ventures.

Reimbursement Revenue – Reimbursements for the purchase of supplies, equipment, personnel services, shipping and other services that are provided at the request of our customers are recorded as revenue when incurred. The related costs are recorded as operating expenses when incurred.

Operating Lease Revenue – Lease income from equipment that we lease to others is recognized on a straight-line basis over the lease term. Lease income recognized during the years ended December 31, 2021, 2020 and 2019 was not material.

Our disaggregated revenue recognized from contracts with customers is included in Note 17.

Accounts Receivable and Contract Liabilities

Accounts receivable is our right to consideration once it becomes unconditional. Payment terms typically range from 30 to 60 days.

Accounts receivable balances were $352 million and $158 million as of December 31, 2021 and 2020, respectively. These balances do not include amounts related to our oil and gas working interests as those contracts are excluded from Topic 606. Accounts receivable balances are included in “Accounts receivable” in the consolidated balance sheets.

We do not have any significant contract asset balances. Contract liabilities include prepayments received from customers prior to the requested services being completed. Once the services are complete and have been invoiced, the prepayment is applied against the customer’s account to offset the accounts receivable balance. Also included in contract liabilities are payments received from customers for the initial mobilization of newly constructed or upgraded rigs that were moved on location to the initial well site. These mobilization payments are allocated to the overall performance obligation and amortized over the initial term of the contract. During the year ended December 31, 2021, no such payments were amortized and recorded in drilling revenue. During the year ended December 31, 2020, approximately $0.1 million was amortized and recorded in drilling revenue.

Total contract liability balances were $60.3 million and $0.6 million as of December 31, 2021 and December 31, 2020, respectively. During the year ended December 31, 2021, contract liabilities in creased by $59.7 million primarily due to customer payments. The majority of the contract liabilities balance is expected to be recognized in 2022. The increase in contract liability balances are included in “Accrued liabilities” in the consolidated balance sheets.

Contract Costs

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

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4. Credit Losses

ASC Topic 326 Current Expected Credit Losses (CECL)

On January 1, 2020, we adopted ASU 2016-13 Financial Instruments – Credit Losses (Topic 326) Measurement of Credit Losses on Financial Instruments, which introduced a new model to measure all expected credit losses for financial instruments held at the reporting date based on historical experience, current conditions and reasonable and supportable forecasts. Our customers are primarily oil and natural gas exploration and production companies, which are collectively exposed to oil and natural gas commodity price risk. Our customers require services from us at various stages of the exploration and production process. Accordingly, we have aggregated our trade receivables by segment. Any customers that have experienced a deterioration in credit quality are removed from the pool and evaluated individually. We utilize an accounts receivable aging schedule and historical credit loss information to estimate expected credit losses. Due to the significant decline in crude oil prices during the quarter ended March 31, 2020 and its related impact to our customers, we increased our historical credit loss rates used to determine our March 31, 2020 allowance for credit losses in the first quarter of 2020. We continued to monitor and evaluate our expected credit losses using these increased credit loss rates throughout the remainder of 2020 and in 2021.

During 2021, we reversed $1.5 million of our credit loss provision related to certain customers who had previously experienced a deterioration in credit quality. Since initially recording loss provisions for these receivables, we have collected portions of the accounts that were deemed uncollectible.

The adoption of the new accounting standard did not have a material impact on our consolidated financial statements and did not result in a transition adjustment to retained earnings.

The allowance for credit losses related to accounts receivable as of December 31, 2020 and 2021, and changes for the periods ended December 31, 2020 and 2021 are as follows (in thousands):

Balance at January 1, 2020 |  | $ | 6,516 |
Provision for expected credit losses |  |  | 5,606 |
Write-offs |  |  | (1,280 | )
Balance at December 31, 2020 |  |  | 10,842 |
Provision for expected credit losses |  |  | (1,500 | )
Write-offs |  |  | (849 | )
Balance at December 31, 2021 |  | $ | 8,493 |

5. Inventory

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

|  | 2021 |  |  | 2020 |
Finished goods |  | $ | 515 |  |  | $ | 600 |
Work-in-process |  |  | 882 |  |  |  | 802 |
Raw materials and supplies |  |  | 40,962 |  |  |  | 31,683 |
Inventory |  | $ | 42,359 |  |  | $ | 33,085 |

We maintain certain surplus quantities of spare parts that serve as backup components and maintenance materials for our directional drilling and Colombia contract drilling operations. In 2021, advances in technologies rendered certain directional drilling equipment, and spare parts used to service that equipment, obsolete. Based on our assessment of limited alternative uses or active markets to recapture costs, we recorded a write-down of $4.0 million. The write-down is recorded in "Operating costs and expenses - Directional drilling" in the consolidated statements of operations.

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6. Property and Equipment

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

|  | 2021 |  |  | 2020 |
Equipment |  | $ | 7,742,101 |  |  | $ | 7,647,451 |
Oil and natural gas properties |  |  | 229,403 |  |  |  | 222,738 |
Buildings |  |  | 182,280 |  |  |  | 193,503 |
Land |  |  | 24,562 |  |  |  | 25,781 |
Total property and equipment |  |  | 8,178,346 |  |  |  | 8,089,473 |
Less accumulated depreciation, depletion, amortization and impairment |  |  | (5,846,591 | ) |  |  | (5,328,432 | )
Property and equipment, net |  | $ | 2,331,755 |  |  | $ | 2,761,041 |

Depreciation, depletion, amortization and impairment — The following table summarizes depreciation, depletion, amortization and impairment expense related to property and equipment, intangible assets and liabilities for 2021, 2020 and 2019 (in thousands):

|  | 2021 |  |  | 2020 |  |  | 2019 |
Depreciation and impairment expense |  | $ | 818,999 |  |  | $ | 644,943 |  |  | $ | 974,206 |
Amortization expense |  |  | 24,606 |  |  |  | 19,281 |  |  |  | 17,722 |
Depletion expense |  |  | 5,573 |  |  |  | 6,686 |  |  |  | 11,945 |
Total |  | $ | 849,178 |  |  | $ | 670,910 |  |  | $ | 1,003,873 |

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. 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. In the second quarter of 2020, we recorded an impairment of $8.3 million related to the closing of our Canadian drilling operations. In 2019, we identified 36 legacy non-APEX® rigs and related equipment that were abandoned. Based on the strong customer preference across the industry for super-spec drilling rigs, we believed the 36 rigs that were abandoned had limited commercial opportunity. We recorded a $173 million charge related to this abandonment.

We also periodically evaluate our pressure pumping 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 pressure pumping 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. In 2019, we recorded a charge of $20.5 million for the write-down of pressure pumping equipment. There was no similar charge in 2020.

We also periodically evaluate our directional drilling 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. During 2019, we recorded a charge of $8.4 million for the write-down of directional drilling equipment. There was no similar charge in 2020.

We review our long-lived assets, including property and equipment, for impairment whenever events or changes in circumstances indicate that the carrying amounts of certain assets may not be recovered over their estimated remaining useful lives (“triggering events”). In connection with this review, assets are grouped at the lowest level at which identifiable cash flows are largely independent of other asset groupings. We estimate future cash flows over the life of the respective assets or asset groupings in our assessment of impairment. These estimates of cash flows are based on historical cyclical trends in the industry as well as our expectations regarding the continuation of these trends in the future. Provisions for asset impairment are charged against income when estimated future cash flows, on an undiscounted basis, are less than the asset’s net book value. Any provision for impairment is measured at fair value.

F-17

2021 Triggering Event Assessment

Based on current commodity prices, our results of operations for the year ended December 31, 2021 and management’s expectations of operating results in future periods, we concluded that no triggering events occurred during the year ended December 31, 2021 with respect to our asset groups within our operating segments. Our expectations of future operating results were based on the assumption that activity levels in all of our reporting segments and our other operations will remain relatively stable or improve in response to relatively stable or increasing oil prices.

2020 Triggering Event Assessment

Due to the decline in the market price of our common stock and commodity prices in the first quarter of 2020, we lowered our expectations with respect to future activity levels in certain of our operating segments. We deemed it necessary to assess the recoverability of our contract drilling, pressure pumping, directional drilling and oilfield rentals asset groups as of March 31, 2020. We performed an analysis as required by ASC 360-10-35 to assess the recoverability of the asset groups within our contract drilling, pressure pumping, directional drilling and oilfield rentals operating segments as of March 31, 2020. With respect to these asset groups, future cash flows were estimated over the expected remaining life of the assets, and we determined that, on an undiscounted basis, expected cash flows exceeded the carrying value of the asset groups, and no impairment was indicated. Expected cash flows, on an undiscounted basis, exceeded the carrying values of the asset groups within the contract drilling, pressure pumping, directional drilling and oilfield rentals operating segments by approximately 15%, 22%, 3% and 9%, respectively.

For the assessment performed in the first quarter of 2020, the expected cash flows for our asset groups i ncluded revenue and operating expense growth rates. Also, the expected cash flows for the contract drilling, pressure pumping, directional drilling and oilfield rentals asset groups were based on the assumption that activity levels in all four segments would generally be lower than levels experienced in the second half of 2019 and the first quarter of 2020 and would begin to recover in 2022 in response to improved oil prices.

After the assessment we performed in the first quarter of 2020, we concluded that no triggering events occurred during the periods thereafter through December 31, 2020 with respect to our asset groups based on the recent results of operations leading up to that date, management’s expectations of operating results in future periods and the prevailing commodity prices at the time.

2019 Triggering Event Assessment

Due to the decline in the market price of our common stock and commodity prices, our results of operations for the quarter ended September 30, 2019 and management’s expectations of operating results in future periods, we lowered our expectations with respect to future activity levels in certain of our operating segments. We deemed it necessary to assess the recoverability of our contract drilling, pressure pumping, directional drilling and oilfield rentals asset groups as of September 30, 2019. We performed an analysis as required by ASC 360-10-35 to assess the recoverability of the asset groups within our contract drilling, pressure pumping, directional drilling and oilfield rentals operating segments as of September 30, 2019. With respect to these asset groups, future cash flows were estimated over the expected remaining life of the assets, and we determined that, on an undiscounted basis, expected cash flows exceeded the carrying value of the asset groups, and no impairment was indicated. Expected cash flows, on an undiscounted basis, exceeded the carrying values of the asset groups within the contract drilling, pressure pumping, directional drilling and oilfield rentals operating segments by approximately 35%, 54%, 23% and 7%, respectively.

For the assessment performed in 2019, the expected cash flows for our asset groups i ncluded revenue and operating expense growth rates. Also, the expected cash flows for the contract drilling, pressure pumping, directional drilling and oilfield rentals asset groups were based on the assumption that activity levels in all four segments would generally be lower than levels experienced in 2019 and would begin to recover in late 2020 or 2021 in response to improved oil prices.

We concluded that no triggering events occurred during the quarter ended December 31, 2019 with respect to our asset groups based on the recent results of operations leading up to that date, management’s expectations of operating results in future periods and the prevailing commodity prices at the time.

F-18

7. Goodwill and Intangible Assets

Goodwill — As a result of a triggering event in the first quarter of 2020, we fully impaired our remaining goodwill balance, and as a result, we had no goodwill balance as of December 31, 2021. At times when we have a goodwill balance, we are required to evaluate goodwill at least annually as of December 31, or when circumstances require, to determine if the fair value of recorded goodwill has decreased below its carrying value. For impairment testing purposes, goodwill is evaluated at the reporting unit level. Our reporting units for impairment testing are our operating segments. We determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying value after considering qualitative, market and other factors, and if this is the case, any necessary goodwill impairment is determined using a quantitative impairment test. From time to time, we may perform quantitative testing for goodwill impairment in lieu of performing the qualitative assessment. If the resulting fair value of goodwill is less than the carrying value of goodwill, an impairment loss would be recognized for the amount of the shortfall.

2020 Triggering Event Assessment

Due to the decline in the market price of our common stock and commodity prices in the first quarter of 2020, we lowered our expectations with respect to future activity levels in our contract drilling reporting unit. We performed a quantitative impairment assessment of our goodwill as of March 31, 2020. In completing the assessment, the fair value of our contract drilling operating segment was estimated using the income approach. The estimate of fair value required the use of significant unobservable inputs, representative of a Level 3 fair value measurement. The assumptions included discount rates, revenue growth rates, operating expense growth rates, and terminal growth rates.

Based on the results of the goodwill impairment test as of March 31, 2020, impairment was indicated in our contract drilling reporting unit. We recognized an impairment charge of $395 million in the quarter ended March 31, 2020 associated with the impairment of all of the goodwill in our contract drilling reporting unit. We had no remaining goodwill balance as of December 31, 2020.

2019 Triggering Event Assessment

Due to the decline in the market price of our common stock and commodity prices leading up to September 30, 2021, our results of operations for the quarter ended September 30, 2019 and our expectations of operating results in future periods, we lowered our expectations with respect to future activity levels in certain of our operating segments. We performed a quantitative impairment assessment of our goodwill as of September 30, 2019. In completing the assessment, the fair value of each reporting unit was estimated using the income approach. The estimate of fair value for each reporting unit required the use of significant unobservable inputs, representative of a Level 3 fair value measurement. The assumptions included discount rates, revenue growth rates, operating expense growth rates, and terminal growth rates.

Based on the results of the goodwill impairment test as of September 30, 2019, the fair value of the contract drilling reporting unit exceeded its carrying value by approximately 13% and we concluded that no impairment was indicated in our contract drilling reporting unit; however, impairment was indicated in our oilfield rentals and electrical controls and automation reporting units included in the other operations segment. We recognized an impairment charge of $17.8 million in 2019 associated with the impairment of all of the goodwill in our oilfield rentals and electrical controls and automation reporting units.

In connection with our annual goodwill impairment assessment as of December 31, 2019, we determined based on an assessment of qualitative factors that it was more likely than not that the fair values of our reporting units were greater than the respective carrying amount. In making this determination, we considered the current and expected levels of commodity prices for oil and natural gas, which influence the overall level of business activity in our reporting units, as well as our 2019 operating results and forecasted operating results for the succeeding year. We also considered our overall market capitalization at December 31, 2019.

Intangible Assets — In 2021, an intangible asset was recorded in our contract drilling operating segment with the acquisition of Pioneer. See Note 2 for additional information. 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 |  | Other operations |  |  | 7.00 |
Developed technology |  | Directional drilling |  |  | 10.00 |
Internal use software |  | Directional drilling |  |  | 5.00 |
Trade name |  | Contract drilling |  |  | 5.00 |

F-19

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.

2021 Triggering Event Assessment

Based on current commodity prices, our results of operations for the year ended December 31, 2021 and management’s expectations of operating results in future periods, we concluded that no triggering events occurred during the year ended December 31, 2021. Our expectations of future operating results were based on the assumption that activity levels in all segments and our other operations will remain relatively stable or improve in response to relatively stable or increasing oil prices.

2020 Triggering Event Assessment

Due to the decline in the market price of our common stock and commodity prices in the first quarter of 2020, we lowered our expectations with respect to future activity levels in certain of our operating segments. We deemed it necessary to assess the recoverability of our contract drilling, pressure pumping, directional drilling and oilfield rentals asset groups as of March 31, 2020. The assessments of recoverability of the asset groups included the respective intangible assets, and no impairment was indicated. See Note 6 for additional information.

After the assessment we performed in the first quarter of 2020, we concluded that no triggering events necessitating an impairment assessment of the intangible assets occurred throughout the remainder of 2020.

2019 Triggering Event Assessment

Due to the decline in the market price of our common stock and commodity prices in 2019, our results of operations for the quarter ended September 30, 2019 and our expectations of operating results in future periods, we lowered our expectations with respect to future activity levels in certain of our operating segments. We deemed it necessary to assess the recoverability of our contract drilling, pressure pumping, directional drilling and oilfield rentals asset groups as of September 30, 2019. The assessments of recoverability of the asset groups included the respective intangible assets, and no impairment was indicated. See Note 6 for additional information.

We concluded that no triggering events necessitating an impairment assessment of the intangible assets had occurred during the quarter ended December 31, 2019.

The gross carrying amount and accumulated amortization of intangible assets as of December 31, 2021 and 2020 are as follows (in thousands):

|  | 2021 |  |  | 2020 |
|  | Gross Carrying |  |  | Accumulated |  |  | Net Carrying |  |  | Gross Carrying |  |  | Accumulated |  |  | Net Carrying |
|  | Amount |  |  | Amortization |  |  | Amount |  |  | Amount |  |  | Amortization |  |  | Amount |
Customer relationships |  | $ | 1,800 |  |  | $ | (814 | ) |  | $ | 986 |  |  | $ | 28,000 |  |  | $ | (26,757 | ) |  | $ | 1,243 |
Developed technology |  |  | 55,772 |  |  |  | (50,996 | ) |  |  | 4,776 |  |  |  | 55,772 |  |  |  | (27,515 | ) |  |  | 28,257 |
Internal use software |  |  | 1,428 |  |  |  | (515 | ) |  |  | 913 |  |  |  | 906 |  |  |  | (319 | ) |  |  | 587 |
Trade name |  |  | 907 |  |  |  | (45 | ) |  |  | 862 |  |  |  | — |  |  |  | — |  |  |  | — |
|  | $ | 59,907 |  |  | $ | (52,370 | ) |  | $ | 7,537 |  |  | $ | 84,678 |  |  | $ | (54,591 | ) |  | $ | 30,087 |

Amortization and impairment expense on intangible assets of approximately $24.0 million, $19.3 million and $17.9 million was recorded for the years ended December 31, 2021, 2020 and 2019, respectively, which included an $11.4 million impairment in 2021. The remaining amortization expense associated with finite-lived intangible assets is expected to be as follows (in thousands):

Year ending December 31, |  |  |
2022 |  | $ | 1,405 |
2023 |  |  | 1,405 |
2024 |  |  | 1,405 |
2025 |  |  | 1,354 |
2026 |  |  | 1,078 |
Thereafter |  |  | 890 |
Total |  | $ | 7,537 |

F-20

8. Accrued Liabilities

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

|  | 2021 |  |  | 2020 |
Salaries, wages, payroll taxes and benefits |  | $ | 52,252 |  |  | $ | 37,627 |
Workers’ compensation liability |  |  | 67,921 |  |  |  | 70,847 |
Property, sales, use and other taxes |  |  | 9,673 |  |  |  | 10,666 |
Insurance, other than workers’ compensation |  |  | 6,494 |  |  |  | 8,462 |
Accrued interest payable |  |  | 11,226 |  |  |  | 11,325 |
Accrued restructuring expenses |  |  | 7,884 |  |  |  | 14,310 |
Customer prepayment |  |  | 60,282 |  |  |  | 599 |
Other |  |  | 22,779 |  |  |  | 21,767 |
Accrued liabilities |  | $ | 238,511 |  |  | $ | 175,603 |

9. Long-Term Debt

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

| Effective Interest Rate |  | December 31, 2021 |  |  | December 31, 2020 |
Term Loan Agreement (1) |  |  | $ | — |  |  | $ | 50,000 |
3.95% Senior Notes | 4.03% |  |  | 509,505 |  |  |  | 509,505 |
5.15% Senior Notes | 5.26% |  |  | 349,250 |  |  |  | 349,250 |
|  |  |  | 858,755 |  |  |  | 908,755 |
Less deferred financing costs and discounts |  |  |  | (6,432 | ) |  |  | (7,271 | )
Total |  |  | $ | 852,323 |  |  | $ | 901,484 |

(1)
The borrowings outstanding under the Term Loan Agreement maturing in June 2022 were previously classified as long-term because we had the ability and intent to repay these obligations utilizing our revolving credit facility.

2019 Term Loan Agreement — On August 22, 2019, we entered into a term loan agreement (“Term Loan Agreement”) among us, as borrower, Wells Fargo Bank, National Association, as administrative agent and lender and the other lender party thereto.

The Term Loan Agreement was a committed senior unsecured term loan facility that permitted a single borrowing of up to $150 million initially, which we drew in full on September 23, 2019. We repaid $50 million of these borrowings in each of 2019 and 2020, and o n December 30, 2021, we repaid the final $50 million of borrowings under the Term Loan Agreement, and as a result had no remaining borrowings under the Term Loan Agreement as of December 31, 2021.

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

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

F-21

Loans under the Credit Agreement bear interest by reference, at our election, to the LIBOR rate or base rate. The applicable margin on LIBOR rate loans varies from 1.00% to 2.00% and the applicable margin on base rate loans varies from 0.00% to 1.00%, in each case determined based upon our credit rating. As of December 31, 2021, the applicable margin on LIBOR rate loans was 1.75% and the applicable margin on base rate loans was 0.75%. A letter of credit fee is payable by us equal to the applicable margin for LIBOR rate loans times the daily amount available to be drawn under outstanding letters of credit. The commitment fee rate payable to the lenders varies from 0.10% to 0.30% based on our credit rating.

None of our subsidiaries are currently required to be a guarantor under the Credit Agreement. However, if any subsidiary guarantees or incurs debt in excess of the Priority Debt Basket (as defined in the Credit Agreement), such subsidiary is required to become a guarantor under the Credit Agreement.

The Credit Agreement contains representations, warranties, affirmative and negative covenants and events of default and associated remedies that we believe are customary for agreements of this nature, including certain restrictions on our ability and the ability of each of our subsidiaries to incur debt and grant liens. If our credit rating is below investment grade at both Moody’s and S&P, we will become subject to a restricted payment covenant, which would require us to have a Pro Forma Debt Service Coverage Ratio (as defined in the Credit Agreement) greater than or equal to 1.50 to 1.00 immediately before and immediately after making any restricted payment. Restricted payments include, among other things, dividend payments, repurchases of our common stock, distributions to holders of our common stock or any other payment or other distribution to third parties on account of our or our subsidiaries’ equity interests. Our credit rating is currently investment grade at one of the two ratings agencies. The Credit Agreement also requires that our total debt to capitalization ratio, expressed as a percentage, not exceed 50%. The Credit Agreement generally defines the total debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the end of the most recently ended fiscal quarter. We were in compliance with these covenants at December 31, 2021.

As of December 31, 2021, we had no borrowings outstanding under our revolving credit facility. We had $0.1 million in letters of credit outstanding under the Credit Agreement at December 31, 2021 and, as a result, had available borrowing capacity of approximately $600 million at that date.

2015 Reimbursement Agreement — On March 16, 2015, we entered into a Reimbursement Agreement (the “Reimbursement Agreement”) with The Bank of Nova Scotia (“Scotiabank”), pursuant to which we may from time to time request that Scotiabank issue an unspecified amount of letters of credit. On October 7, 2021, an additional $7.3 million of letters of credit were issued by Scotiabank in connection with the closing of the Pioneer acquisition. As of December 31, 2021, we had $71.4 million in letters of credit outstanding under the Reimbursement Agreement.

Under the terms of the Reimbursement Agreement, we will reimburse Scotiabank on demand for any amounts that Scotiabank has disbursed under any letters of credit. Fees, charges and other reasonable expenses for the issuance of letters of credit are payable by us at the time of issuance at such rates and amounts as are in accordance with Scotiabank’s prevailing practice. We are obligated to pay to Scotiabank interest on all amounts not paid by us on the date of demand or when otherwise due at the LIBOR rate plus 2.25% per annum, calculated daily and payable monthly, in arrears, on the basis of a calendar year for the actual number of days elapsed, with interest on overdue interest at the same rate as on the reimbursement amounts.

We have also agreed that if obligations under the Credit Agreement are secured by liens on any of our or our subsidiaries’ property, then our reimbursement obligations and (to the extent similar obligations would be secured under the Credit Agreement) other obligations under the Reimbursement Agreement and any letters of credit will be equally and ratably secured by all property subject to such liens securing the Credit Agreement.

Pursuant to a Continuing Guaranty dated as of March 16, 2015, our payment obligations under the Reimbursement Agreement are jointly and severally guaranteed as to payment and not as to collection by our subsidiaries that from time to time guarantee payment under the Credit Agreement. None of our subsidiaries are currently required to guarantee payment under the Credit Agreement.

Series A Senior Notes and Series B Senior Notes — On October 5, 2010, we completed the issuance and sale of $300 million in aggregate principal amount of our 4.97% Series A Senior Notes due October 5, 2020 (the “Series A Notes”) in a private placement. The Series A Notes bore interest at a rate of 4.97% per annum. On September 25, 2019, we fully prepaid the Series A Notes. The total amount of the prepayment, including the applicable “make-whole” premium, was approximately $308 million, which represents 100% of the principal and the “make-whole” premium to the prepayment date.

F-22

On June 14, 2012, we completed the issuance and sale of $300 million in aggregate principal amount of our 4.27% Series B Senior Notes due June 14, 2022 (the “Series B Notes”) in a private placement. The Series B Notes bore interest at a rate of 4.27% per annum. On December 16, 2019, we fully prepaid the Series B Notes. The total amount of the prepayment, including the applicable “make-whole” premium, was approximately $315 million, which represents 100% of the principal and the “make-whole” premium to the prepayment date.

Primarily as a result of the “make-whole” premiums, we incurred an $8.2 million loss on early extinguishment of the Series A Notes in the three months ended September 30, 2019, and a $15.8 million loss on early extinguishment of the Series B Notes in the three months ended December 31, 2019, which were included in “Interest expense, net of amount capitalized” in the consolidated statements of operations.

2028 Senior Notes and 2029 Senior Notes — On January 19, 2018, we completed an offering of $525 million in aggregate principal amount of our 3.95% Senior Notes due 2028 (the “2028 Notes”). The net proceeds before offering expenses were approximately $521 million, of which we used $239 million to repay amounts outstanding under our revolving credit facility. On November 15, 2019, we completed an offering of $350 million in aggregate principal amount of our 5.15% Senior Notes due 2029 (the “2029 Notes”). The net proceeds before offering expenses were approximately $347 million. We used a portion of the net proceeds from the offering to prepay our Series B Notes. The remaining net proceeds and available cash on hand was used to repay $50 million of the borrowings under the Term Loan Agreement in 2019.

During the fourth quarter of 2020, we elected to repurchase portions of our 2028 Notes and 2029 Notes in the open market. The principal amounts retired through these transactions totaled $15.5 million related to our 2028 Notes and $0.8 million related to our 2029 Notes, plus accrued interest. We recorded corresponding gains on the extinguishment of these amounts totaling $3.4 million and $0.2 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 the consolidated statements of operations.

We pay interest on the 2028 Notes on February 1 and August 1 of each year. The 2028 Notes will mature on February 1, 2028. The 2028 Notes bear interest at a rate of 3.95% per annum.

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

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

At our option, we may redeem the Senior Notes in whole or in part, at any time or from time to time at a redemption price equal to 100% of the principal amount of such Senior Notes to be redeemed, plus accrued and unpaid interest, if any, on those Senior Notes to the redemption date, plus a “make-whole” premium. Additionally, commencing on November 1, 2027, in the case of the 2028 Notes, and on August 15, 2029, in the case of the 2029 Notes, at our option, we may redeem the respective Senior Notes in whole or in part, at a redemption price equal to 100% of the principal amount of the Senior Notes to be redeemed, plus accrued and unpaid interest, if any, on those Senior Notes to the redemption date.

The indentures pursuant to which the Senior Notes were issued include covenants that, among other things, limit our and our subsidiaries’ ability to incur certain liens, engage in sale and lease-back transactions or consolidate, merge, or transfer all or substantially all of their assets. These covenants are subject to important qualifications and limitations set forth in the indentures.

Upon the occurrence of a change of control triggering event, as defined in the indentures, each holder of the Senior Notes may require us to purchase all or a portion of such holder’s Senior Notes at a price equal to 101% of their principal amount, plus accrued and unpaid interest, if any, to, but excluding, the repurchase date.

The indentures also provide for events of default which, if any of them occurs, would permit or require the principal of, premium, if any, and accrued interest, if any, on the Senior Notes to become or to be declared due and payable.

F-23

Debt issuance costs — We incurred approximately $0.2 million in debt issuance costs in connection with the Term Loan Agreement. We incurred approximately $4.6 million in debt issuance costs in connection with the Credit Agreement. We also incurred an additional $0.4 million in debt issuance costs in connection with our entry into Amendment No. 2. We incurred approximately $1.9 million in debt issuance costs in connection with the Series A Notes and approximately $1.6 million in debt issuance costs in connection with the Series B Notes. We incurred approximately $1.6 million in debt issuance costs in connection with the 2028 Notes and approximately $1.0 million in debt issuance costs in connection with the 2029 Notes. These costs were deferred and are being recognized as interest expense over the term of the underlying debt. Debt issuance costs, except those related to line-of-credit arrangements, are presented in the balance sheet as a direct reduction of the carrying amount of the related debt. Debt issuance costs related to line-of-credit arrangements are included in “Other non-current assets” in the consolidated balance sheets. Amortization of debt issuance costs is reported as interest expense.

Interest expense related to the amortization of debt issuance costs was approximately $1.0 million, $1.1 million and $2.0 million for the years ended December 31, 2021, 2020 and 2019, respectively. Amortization of debt issuance costs for the year ended December 31, 2021 includes minimal debt issuance costs that were expensed as a result of the complete prepayment of our borrowings under our Term Loan Agreement. Amortization of debt issuance costs for the year ended December 31, 2020 includes $0.1 million of debt issuance costs that were expensed as a result of the early redemption of a portion of our 2028 Notes and our 2029 Notes as well as the partial repayment of our borrowings under our Term Loan Agreement. Amortization of debt issuance costs for the year ended December 31, 2019 includes $0.2 million of debt issuance costs that were expensed as a result of the Series A Notes prepayment, $0.4 million of debt issuance costs that were expensed as a result of the Series B Notes prepayment and approximately $0.1 million of debt issuance costs that were expensed as a result of the Term Loan Agreement partial repayment.

Presented below is a schedule of the principal repayment requirements of long-term debt by fiscal year as of December 31, 2021 (in thousands):

Year ending December 31, |  |  |
2022 |  | $ | — |
2023 |  |  | — |
2024 |  |  | — |
2025 |  |  | — |
2026 |  |  | — |
Thereafter |  |  | 858,755 |
Total |  | $ | 858,755 |

10. Commitments, Contingencies and Other Matters

Commitments – As of December 31, 2021, we maintained letters of credit in the aggregate amount of $71.5 million primarily for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under the terms of the underlying insurance contracts. These letters of credit expire annually at various times during the year and are typically renewed. As of December 31, 2021, no amounts had been drawn under the letters of credit.

As of December 31, 2021, we had commitments to purchase major equipment totaling approximately $99.0 million for our contract drilling, pressure pumping, directional drilling and oilfield rentals businesses.

Our pressure pumping business has entered into agreements to purchase minimum quantities of proppants and chemicals from certain vendors. The remaining terms of the agreements are less than one year. I n the event the required minimum quantities are not purchased during any contract year, we could be required to make a liquidated damages payment to the respective vendor for any shortfall. In 2017, we entered into a capacity reservation agreement that required a cash deposit to increase our access to finer grades of sand for our pressure pumping business. As market prices for sand substantially decreased since 2017, we purchased lower cost sand outside of this capacity reservation contract and recorded a charge of $9.2 million and $12.7 million in the second quarters of 2020 and 2019, respectively, to revalue the deposit to its expected realizable value. There is no value assigned to the capacity reservation contract subsequent to the charge recorded in the second quarter of 2020.

F-24

Contingencies – Our operations are subject to many hazards inherent in the businesses in which it operates, including inclement weather, blowouts, explosions, fires, loss of well control, motor vehicle accidents, equipment failure, 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 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.

We maintain insurance coverage of types and amounts that we believe to be customary in the industry, but are not fully insured against all risks, either because insurance is not available or because of the high premium costs. The insurance coverage that we maintain includes insurance 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 and insurance for other specific risks. We cannot assure, however, that any insurance obtained will be adequate to cover any losses or liabilities, or that this insurance will continue to be available, or available on terms that are acceptable to us. 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 accept 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, a $2.0 million per occurrence deductible on our primary automobile liability insurance coverage, and a $5.0 million per occurrence deductible on our excess automobile liability insurance coverage. 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.

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

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.

F-25

We have Employment Agreements with our Chief Executive Officer, Chief Financial Officer, General Counsel and the President of our subsidiary, Patterson-UTI Drilling Company LLC (“Patterson-UTI Drilling”). 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 either (i) providing written notice 10 days before the effective date of such termination and by granting at least 10 days 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, General Counsel and President of Patterson-UTI Drilling) 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 options and restricted stock awards on the 60th day following the executive’s termination, 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, which for the President of Patterson-UTI Drilling includes a change in control of us or, in certain circumstances, of Patterson-UTI Drilling), 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, General Counsel and President of Patterson-UTI Drilling) of subsidized benefits continuation coverage.

11. Stockholders’ Equity

Cash Dividend — On February 9, 2022, our Board of Directors approved a cash dividend on our common stock in the amount of $0.04 per share to be paid on March 17, 2022 to holders of record as of March 3, 2022. The amount and timing of all future dividend payments, if any, are subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of our debt agreements and other factors. Our Board of Directors may, without advance notice, reduce or suspend our dividend in order to improve our financial flexibility and best 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 — On September 6, 2013, our Board of Directors approved a stock buyback program that authorized purchases of up to $200 million of our common stock in open market or privately negotiated transactions. The authorized repurchases under this program were subsequently increased in July 2018 and February 2019, and on July 24, 2019, our Board of Directors approved another increase of the authorization under the stock buyback program to allow for $250 million of future share repurchases. All purchases executed to date have been through open market transactions. Purchases under the program are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Purchases may be made at any time without prior notice. There is no expiration date associated with the buyback program. As of December 31, 2021, we had remaining authorization to purchase approximately $130 million of our outstanding common stock under the stock buyback program. Shares of stock purchased under the buyback program are held as treasury shares.

We acquired shares of stock from employees during 2021, 2020 and 2019 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”), 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.

F-26

Treasury stock acquisitions during the years ended December 31, 2021, 2020 and 2019 were as follows (dollars in thousands):

|  | 2021 |  |  | 2020 |  |  | 2019 |
|  | Shares |  |  | Cost |  |  | Shares |  |  | Cost |  |  | Shares |  |  | Cost |
Treasury shares at beginning of period |  |  | 83,402,322 |  |  | $ | 1,366,313 |  |  |  | 77,336,387 |  |  | $ | 1,345,134 |  |  |  | 53,701,096 |  |  | $ | 1,080,448 |
Purchases pursuant to stock buyback program |  |  | — |  |  |  | — |  |  |  | 5,826,266 |  |  |  | 20,000 |  |  |  | 22,566,331 |  |  |  | 250,109 |
Acquisitions pursuant to long-term incentive plan |  |  | 451,196 |  |  |  | 3,727 |  |  |  | 239,669 |  |  |  | 1,179 |  |  |  | 1,037,947 |  |  |  | 14,205 |
Purchases in connection with Pioneer acquisition |  |  | 275,477 |  |  |  | 2,601 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Other |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 31,013 |  |  |  | 372 |
Treasury shares at end of period |  |  | 84,128,995 |  |  | $ | 1,372,641 |  |  |  | 83,402,322 |  |  | $ | 1,366,313 |  |  |  | 77,336,387 |  |  | $ | 1,345,134 |

Stockholder Rights Agreement — On April 22, 2020, our Board of Directors adopted a stockholder rights agreement and declared a dividend of one right (a “Right”) for each outstanding share of our common stock to stockholders of record at the close of business on May 8, 2020. Each Right entitled its holder, subject to the terms of the Rights Agreement (as defined below), to purchase from us one one-thousandth of a share of our Series A Junior Participating Preferred Stock, par value $0.01 per share, at an exercise price of $17.00 per Right, subject to adjustment. The description and terms of the Rights were set forth in a stockholder rights agreement, dated as of April 22, 2020 (the “Rights Agreement”), between us and Continental Stock Transfer & Trust Company, as rights agent (the “Rights Agent”). The Rights Agreement expired on April 21, 2021.

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, restricted stock or restricted stock units that have included service conditions and, in certain cases, performance conditions. Our share-based awards also include share-settled performance unit awards. Share-settled performance unit awards are accounted for as equity awards. In 2020, we granted performance-based cash-settled phantom units, which are accounted for as a liability classified award. We issue shares of common stock when vested stock options are exercised, when restricted stock is granted and when restricted stock units and share-settled performance unit awards vest.

On June 3, 2021, our stockholders approved the 2021 Plan. No additional awards will be granted under any of our previously existing plans. The aggregate number of shares of Common Stock authorized for grant under the 2021 Plan is approximately 13.5 million, which includes approximately 4.9 million shares previously authorized under our 2014 Plan.

Our share-based compensation plans at December 31, 2021 are as follows:

|  | Shares |  |  | Shares Underlying |  |  | Shares |
|  | Authorized |  |  | Awards |  |  | Available |
Plan Name |  | for Grant |  |  | Outstanding |  |  | for Grant |
2021 Plan |  |  | 13,467,480 |  |  |  | 2,483,250 |  |  |  | 8,288,582 |
2014 Plan |  |  | — |  |  |  | 4,986,734 |  |  |  | — |
Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, as amended |  |  | — |  |  |  | 1,487,500 |  |  |  | — |

A summary of the 2021 Plan follows:

•
The Compensation Committee of the Board of Directors administers the 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 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.

F-27

•
The 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 Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan and 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.

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, 2021, 2020 and 2019.

Stock option activity for the year ended December 31, 2021 follows:

|  |  |  |  | Weighted Average |
|  | Shares |  |  | Exercise Price Per Share |
Outstanding at beginning of year |  |  | 4,026,150 |  |  | $ | 21.63 |
Exercised |  |  | — |  |  | $ | — |
Expired |  |  | (306,000 | ) |  | $ | 30.10 |
Outstanding at end of year |  |  | 3,720,150 |  |  | $ | 20.93 |
Exercisable at end of year |  |  | 3,720,150 |  |  | $ | 20.93 |

Options outstanding and exercisable at December 31, 2021 have no intrinsic value and a weighted-average remaining contractual term of 2.45 years. Additional information with respect to options granted, vested and exercised during the years ended December 31, 2021, 2020 and 2019 follows (in thousands, except per share data):

|  | 2021 |  |  | 2020 |  |  | 2019 |
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 |  |  | $ | 89 |  |  | $ | 543 |
Aggregate intrinsic value of stock options exercised |  | $ | — |  |  | $ | — |  |  | $ | — |

As of December 31, 2021, no options to purchase shares were outstanding and not vested.

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

Restricted stock unit activity for the year ended December 31, 2021 follows:

|  |  |  |  |  |  |  | Weighted Average |
|  | Time |  |  | Performance |  |  | Grant Date Fair |
|  | Based |  |  | Based |  |  | Value Per Share |
Non-vested restricted stock units outstanding at beginning of year |  |  | 2,741,548 |  |  |  | 359,315 |  |  | $ | 9.52 |
Granted |  |  | 1,797,875 |  |  |  | — |  |  | $ | 8.32 |
Vested |  |  | (1,345,034 | ) |  |  | — |  |  | $ | 10.89 |
Forfeited |  |  | (149,670 | ) |  |  | — |  |  | $ | 10.33 |
Non-vested restricted stock units outstanding at end of year |  |  | 3,044,719 |  |  |  | 359,315 |  |  | $ | 8.31 |

As of December 31, 2021, approximately 3.3 million non-vested restricted stock units outstanding are expected to vest. Additional information as of December 31, 2021 with respect to these non-vested restricted stock units follows (dollars in thousands):

Aggregate intrinsic value |  | $ | 27,977 |
Weighted-average remaining vesting period |  | 1.66 years |
Unrecognized compensation cost |  | $ | 17,290 |

F-28

Performance Unit Awards — We have granted share-settled performance unit awards to certain employees (the “Performance Units”) on an annual basis since 2010. The Performance Units provide for the recipients to receive a grant of shares of common stock upon the achievement of certain performance goals during a specified period established by the Compensation Committee. The performance period for the Performance Units is 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, the peer group also includes three market indices. These goals are considered to be market conditions under the relevant accounting standards and the market conditions were factored into the determination of the fair value of the respective Performance Units. Under the Performance Units granted beginning in April 2019, the recipients will receive the target number of shares if our total shareholder return during the performance period, when compared to the peer group, is at the 55 th percentile. If our total shareholder return during the performance period, when compared to the peer group, is at the 75 th percentile or higher, then the recipients will receive two times the target number of shares. If our total shareholder return during the performance period, when compared to the peer group, is at the 25 th percentile, then the recipients will only receive one-half of the target number of shares. If our total shareholder return during the performance period, when compared to the peer group, is between the 25 th and 55 th percentile, or the 55 th and 75 th percentile, then the shares to be received by the recipients will be determined using linear interpolation for levels of achievement between these points.

Under the Performance Units granted beginning in April 2019, the payout shall not exceed the target number of shares if our total shareholder return is negative or zero. Additionally, the Performance Units granted in April 2020 will not pay out if our total shareholder return is not equal to or greater than the total stockholder return of the S&P 500 Index for the performance period.

The total target number of shares with respect to the Performance Units for the years 2016-2021 is set forth below:

|  | 2021 |  |  | 2020 |  |  | 2019 |  |  | 2018 |  |  | 2017 |  |  | 2016 |
|  | Performance |  |  | Performance |  |  | Performance |  |  | Performance |  |  | Performance |  |  | Performance |
|  | Unit Awards |  |  | Unit Awards |  |  | Unit Awards |  |  | Unit Awards |  |  | Unit Awards |  |  | Unit Awards |
Target number of shares |  |  | 843,000 |  |  |  | 500,500 |  |  |  | 489,800 |  |  |  | 310,700 |  |  |  | 186,198 |  |  |  | 185,000 |

In April 2019, 185,000 shares were issued to settle the 2016 Performance Units. In May 2020, 332,773 shares were issued to settle the 2017 Performance Units. In April 2021, 621,400 shares were issued to settle the 2018 Performance Units. The Performance Units granted in 2019, 2020 and 2021 have not reached the end of their respective performance periods.

Because the Performance Units are share-settled awards, they are accounted for as equity awards and measured at fair value on the date of grant using a Monte Carlo simulation model. The fair value of the Performance Units is set forth below (in thousands):

|  | 2021 |  |  | 2020 |  |  | 2019 |  |  | 2018 |  |  | 2017 |  |  | 2016 |
|  | 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 |  | $ | 7,225 |  |  | $ | 826 |  |  | $ | 9,958 |  |  | $ | 8,004 |  |  | $ | 5,780 |  |  | $ | 3,854 |

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):

|  | 2021 |  |  | 2020 |  |  | 2019 |  |  | 2018 |  |  | 2017 |  |  | 2016 |
|  | Performance |  |  | Performance |  |  | Performance |  |  | Performance |  |  | Performance |  |  | Performance |
|  | Unit Awards |  |  | Unit Awards |  |  | Unit Awards |  |  | Unit Awards |  |  | Unit Awards |  |  | Unit Awards |
Year ended December 31, 2021 |  | $ | 1,806 |  |  | $ | 275 |  |  | $ | 3,319 |  |  | $ | 667 |  |  | NA |  |  | NA |
Year ended December 31, 2020 |  | NA |  |  | $ | 206 |  |  | $ | 3,319 |  |  | $ | 2,668 |  |  | $ | 642 |  |  | NA |
Year ended December 31, 2019 |  | NA |  |  | NA |  |  | $ | 2,489 |  |  | $ | 2,668 |  |  | $ | 1,927 |  |  | $ | 321 |

As of December 31, 2021, we had unrecognized compensation cost of $6.6 million related to our unvested Performance Units. The weighted-average remaining vesting period for these unvested Performance Units was 1.44 years as of December 31, 2021.

Dividends on Equity Awards – Non-forfeitable cash dividends are paid on restricted stock awards and dividend equivalents are paid or accrued on certain restricted stock units. These dividends are recognized as follows:

•
Dividends are recognized as reductions of retained earnings for the portion of restricted stock awards expected to vest.
•
Dividends are recognized as additional compensation cost for the portion of restricted stock awards that are not expected to vest or that ultimately do not vest.
•
Dividend equivalents are recognized as reductions of retained earnings for the portion of restricted stock units expected to vest.

F-29

•
Dividend equivalents are recognized as additional compensation cost for the portion of restricted stock units that are not expected to vest or that ultimately do not 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 may earn from 0% to 200% of a target award of 298,500 phantom units based on our achievement of the same performance conditions over the same p erformance p eriod that applies to the Performance Units granted in April 2020, as described above. Earned Phantom Units, if any, will be settled in 2023, following completion of the three-year p erformance p eriod, in a cash payment equal to the number of earned phantom units multiplied by our average trading price per share over the twenty consecutive trading days ending March 31, 2023. Because the Phantom Units are cash-settled awards, they are accounted for as a liability classified award. The grant date fair value of the Phantom Units was $1.2 million. Compensation expense is recognized on a straight-line basis over the performance period, with the amount recognized fluctuating as a result of the Phantom Units being remeasured to fair value at the end of each reporting period due to their liability-award classification. We recognized $1.8 million and $0.6 million compensation expense associated with the Phantom Units in 2021 and 2020, respectively.

13. Leases

ASC Topic 842 Leases

On January 1, 2019, we adopted the new lease guidance under Topic 842, Leases, using the modified retrospective approach to each lease that existed at the date of initial application as well as leases entered into after that date. We have elected to report all leases at the beginning of the period of adoption and not restate our comparative periods. This standard does not apply to leases to explore for or use minerals, oil, natural gas and similar non-regenerative resources, including the intangible right to explore for those natural resources and rights to use the land in which those natural resources are contained.

We have entered into operating leases for operating locations, corporate offices and certain operating equipment. These leases have remaining lease terms of five months to seven years as of December 31, 2021. Currently, we do not have any finance leases. 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. We have elected the short-term lease recognition practical expedient whereby right-of-use assets and lease liabilities are not recognized for leasing arrangements with an initial term of one year or less.

Topic 842 requires that lessees and lessors discount lease payments at the lease commencement date using the rate implicit in the lease, if available, or the lessee’s incremental borrowing rate. We use the implicit rate when readily determinable. 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 fourth quarter of 2019, we had entered into a sale-leaseback transaction that qualified as a sale. We sold a facility for proceeds of $10.2 million and concurrently entered into an operating lease agreement with the unrelated third-party for certain floors of the building for a 58-month term. The associated gain on sale of approximately $0.8 million was included in “Other operating expenses (income), net” in the consolidated statements of operations.

For the year ended December 31, 2020, we entered into two new facility leases and recorded an increase to the operating lease right-of-use assets and corresponding operating lease liabilities of approximately $1.5 million. We also extended two facilities leases and recorded an increase to the operating lease right-of-use assets and corresponding operating lease liabilities of approximately $0.2 million. We terminated four facility leases and three operating equipment leases and recorded a decrease to the operating lease right-of-use assets of approximately $0.4 million and corresponding lease liabilities of approximately $2.2 million. The right-of-use assets that were formally terminated were partially impaired in the second quarter of 2020 in conjunction with our restructuring plan. See Note 20 for additional information on our restructuring expenses.

For the year ended December 31, 2021, we entered into one new facility lease and recorded an increase to the operating lease right-of-use asset and corresponding operating lease liability of approximately $0.7 million. We also acquired five facility leases as part of the Pioneer acquisition in the fourth quarter of 2021, and recorded an increase to the operating lease right-of-use assets of approximately $4.1 million and corresponding operating lease liabilities of approximately $4.3 million. We transferred one of these facility leases as part of the Clearwell sale in the fourth quarter of 2021, and recorded a decrease to the operating lease right-of-use asset and corresponding lease liability of approximately $0.2 million. We extended three facilities leases and recorded an increase to the operating lease right-of-use assets and corresponding lease liabilities of approximately $1.6 million. We terminated two facility leases and recorded a decrease to the operating lease liabilities of approximately $0.5 million. The right-of-use assets that were formally terminated were previously impaired in 2020 and 2019.

F-30

Practical Expedients Adopted with Topic 842

We have elected to adopt the following practical expedients upon the transition date to Topic 842 on January 1, 2019:

•
Transitional practical expedients package: An entity may elect to apply the listed practical expedients as a package to all the leases that commenced before the effective date. The practical expedients are:
a.
The entity need not reassess whether any expired or existing contracts are or contain leases;
b.
The entity need not reassess the lease classification for expired or existing contracts;
c.
The entity need not reassess initial direct costs for any existing leases.
•
Use of portfolio approach: An entity can apply this guidance to a portfolio of leases with similar characteristics if the entity reasonably expects that the application of the leases model to the portfolio would not differ materially from the application of the lease model to the individual leases in that portfolio. This approach can also be applied to other aspects of the leases guidance for which lessees/lessors need to make judgments and estimates, such as determining the discount rate and determining and reassessing the lease term.
•
Lease and non-lease components: As a practical expedient, lease and non-lease components may be combined where the revenue recognition pattern is the same and where the lease component, when accounted for separately, would be considered an operating lease. Our contract drilling, pressure pumping and directional drilling contracts contain a lease component related to the underlying equipment utilized, in addition to the service component provided by our crews and expertise to operate the related equipment. We have concluded that the non-lease service of operating our equipment and providing expertise in the services provided to customers is predominant in our drilling, pressure pumping and directional drilling contracts. With the election of this practical expedient, we will continue to present a single performance obligation for these contracts under the revenue guidance in ASC 606.

Lease expense consisted of the following for the years ended December 31, 2021, 2020, and 2019 (in thousands):

|  | Year Ended |  |  | Year Ended |  |  | Year Ended |
|  | December 31, 2021 |  |  | December 31, 2020 |  |  | December 31, 2019 |
Operating lease cost |  | $ | 4,984 |  |  | $ | 6,911 |  |  | $ | 10,944 |
Short-term lease expense (1) |  |  | 41 |  |  |  | 2 |  |  |  | 440 |
Total lease expense |  | $ | 5,025 |  |  | $ | 6,913 |  |  | $ | 11,384 |

(1)
Short-term lease expense represents expense related to leases with a contract term of one year or less.

Supplemental cash flow information related to leases for the years ended December 31, 2021, 2020 and 2019 is as follows (in thousands):

|  | Year Ended |  |  | Year Ended |  |  | Year Ended |
|  | December 31, 2021 |  |  | December 31, 2020 |  |  | December 31, 2019 |
Cash paid for amounts included in the measurement of lease liabilities: |  |  |  |  |  |  |  |  |
Operating cash flows from operating leases |  | $ | 7,323 |  |  | $ | 11,576 |  |  | $ | 10,033 |
Right of use assets obtained in exchange for lease obligations: |  |  |  |  |  |  |  |  |
Operating leases |  | $ | 6,413 |  |  | $ | 1,763 |  |  | $ | 10,870 |

Supplemental balance sheet information related to leases as of December 31, 2021 and 2020 is as follows:

|  | December 31, 2021 |  |  | December 31, 2020 |
Weighted Average Remaining Lease Term: |  |  |  |  |  |
Operating leases | 4.8 years |  | 5.2 years |
Weighted Average Discount Rate: |  |  |  |  |  |
Operating leases |  |  | 3.8 | % |  |  | 4.1 | %

F-31

Maturities of operating lease liabilities as of December 31, 2021 are as follows (in thousands):

Year ending December 31, |  |  |
2022 |  | $ | 7,662 |
2023 |  |  | 5,670 |
2024 |  |  | 4,390 |
2025 |  |  | 3,354 |
2026 |  |  | 2,691 |
Thereafter |  |  | 3,508 |
Total lease payments |  |  | 27,275 |
Less imputed interest |  |  | (2,276 | )
Total |  | $ | 24,999 |

14. Income Taxes

Loss before income taxes for the U.S. for years ended December 31, 2021, 2020 and 2019 are $721 million, $917 million, and $500 million, respectively. Income before income taxes for non-U.S. jurisdictions for the year ended December 31, 2021 is $0.9 million. Loss before income taxes for non-U.S. jurisdictions for years ended December 31, 2020 and 2019 are $14.2 million and $30.5 million, respectively.

Components of the income tax provision applicable to federal, state and foreign income taxes for the years ended December 31, 2021, 2020 and 2019 are as follows (in thousands):

|  | 2021 |  |  | 2020 |  |  | 2019 |
Federal income tax benefit: |  |  |  |  |  |  |  |  |
Current |  | $ | — |  |  | $ | (1,977 | ) |  | $ | (1,976 | )
Deferred |  |  | (86,878 | ) |  |  | (107,334 | ) |  |  | (90,441 | )
|  |  | (86,878 | ) |  |  | (109,311 | ) |  |  | (92,417 | )
State income tax expense (benefit): |  |  |  |  |  |  |  |  |
Current |  |  | 144 |  |  |  | 225 |  |  |  | 851 |
Deferred |  |  | 23,028 |  |  |  | (17,949 | ) |  |  | (11,593 | )
|  |  | 23,172 |  |  |  | (17,724 | ) |  |  | (10,742 | )
Foreign income tax expense (benefit): |  |  |  |  |  |  |  |  |
Current |  |  | 134 |  |  |  | (291 | ) |  |  | (348 | )
Deferred |  |  | 870 |  |  | — |  |  |  | (1,168 | )
|  |  | 1,004 |  |  |  | (291 | ) |  |  | (1,516 | )
Total income tax benefit: |  |  |  |  |  |  |  |  |
Current |  |  | 278 |  |  |  | (2,043 | ) |  |  | (1,473 | )
Deferred |  |  | (62,980 | ) |  |  | (125,283 | ) |  |  | (103,202 | )
Total income tax benefit: |  | $ | (62,702 | ) |  | $ | (127,326 | ) |  | $ | (104,675 | )

The difference between the statutory U.S. federal income tax rate and the effective income tax rate for the years ended December 31, 2021, 2020 and 2019 is summarized as follows:

|  | 2021 |  |  | 2020 |  |  | 2019 |
Statutory tax rate |  |  | 21.0 | % |  |  | 21.0 | % |  |  | 21.0 | %
State income taxes - net of the federal income tax benefit |  |  | 3.0 |  |  |  | 1.7 |  |  |  | 1.4 |
Goodwill impairment |  |  | — |  |  |  | (8.2 | ) |  |  | (0.7 | )
Permanent differences |  |  | (0.8 | ) |  |  | (0.6 | ) |  |  | (1.2 | )
Valuation allowance |  |  | (13.3 | ) |  |  | (0.2 | ) |  |  | (0.8 | )
State deferred tax remeasurement |  |  | (0.8 | ) |  |  | — |  |  |  | (1.1 | )
Other differences, net |  |  | (0.4 | ) |  |  | — |  |  |  | 1.1 |
Effective tax rate |  |  | 8.7 | % |  |  | 13.7 | % |  |  | 19.7 | %

The effective tax rate decreased by approximately 5.0% to 8.7% for 2021 compared to 13.7% for 2020. The difference was primarily due to nondeductible goodwill impairment charges in 2020 impacting the effective tax rate and changes in valuation allowance positions between 2020 and 2021.

F-32

The tax effect of temporary differences and tax attributes representing deferred tax assets and liabilities at December 31, 2021 and 2020 are as follows (in thousands):

|  | 2021 |  |  | 2020 |
Deferred tax assets: |  |  |  |  |  |
Net operating loss carryforwards |  | $ | 457,362 |  |  | $ | 370,875 |
Tax credits |  |  | 4,453 |  |  |  | 4,918 |
Expense associated with stock-based compensation |  |  | 9,364 |  |  |  | 11,252 |
Workers' compensation allowance |  |  | 14,833 |  |  |  | 17,177 |
Other deferred tax asset |  |  | 26,483 |  |  |  | 24,735 |
|  |  | 512,495 |  |  |  | 428,957 |
Less: |  |  |  |  |  |
Valuation allowance |  |  | (189,737 | ) |  |  | (19,133 | )
Total deferred tax assets |  |  | 322,758 |  |  |  | 409,824 |
Deferred tax liabilities: |  |  |  |  |  |
Property and equipment basis difference |  |  | (335,980 | ) |  |  | (475,025 | )
Other |  |  | (12,037 | ) |  |  | (12,475 | )
Total deferred tax liabilities |  |  | (348,017 | ) |  |  | (487,500 | )
Net deferred tax liability |  | $ | (25,259 | ) |  | $ | (77,676 | )

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized, and when necessary, valuation allowances are provided. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. We assess the realizability of our deferred tax assets quarterly and consider carryback availability, the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. In 2021, we recorded an additional $170.6 million of valuation allowances against our net deferred tax assets. This primarily related to U.S. federal and state deferred tax assets, as well as valuation allowances that were recorded through the acquisition of Pioneer.

For income tax purposes, we have approximately $1.7 billion of gross federal net operating losses, approximately $52.4 million of gross Canadian net operating losses, approximately $25.2 million of gross Colombian net operating losses and approximately $1.1 billion of post-apportionment state net operating losses as of December 31, 2021, before valuation allowances. The majority of federal net operating losses will expire in varying amounts, if unused, between 2031 and 2037. 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 2041. Colombian net operating losses will expire in varying amounts, if unused, between 2028 and 2033. State net operating losses will expire in varying amounts, if unused, between 2022 and 2041.

As of December 31, 2021, we had no 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, 2021, the tax years ended December 31, 2014 through December 31, 2020 are open for examination by U.S. taxing authorities. As of December 31, 2021, the tax years ended December 31, 2014 through December 31, 2020 are open for examination by Canadian taxing authorities. As of December 31, 2021, the tax years ended December 31, 2015 through December 31, 2020 are open for examination by Colombian taxing authorities.

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.

We continue to elect permanent reinvestment of unremitted earnings in foreign jurisdictions and we intend to do so for the foreseeable future. If we were to repatriate earnings, in the form of dividends or otherwise, we may be subject to certain income and/or withholding taxes (subject to an adjustment for foreign tax credits).

F-33

15. Earnings Per Share

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

Basic EPS excludes dilution and is 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, non-vested shares of restricted stock, performance units and restricted stock units. The dilutive effect of stock options, performance units and restricted stock units is determined using the treasury stock method.

The following table presents information necessary to calculate net loss per share for the years ended December 31, 2021, 2020 and 2019, 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):

|  | 2021 |  |  | 2020 |  |  | 2019 |
BASIC EPS: |  |  |  |  |  |  |  |  |
Net loss from continuing operations attributed to common stockholders |  | $ | (657,079 | ) |  | $ | (803,692 | ) |  | $ | (425,703 | )
Net income from discontinued operations attributed to common stockholders |  | $ | 2,534 |  |  | $ | — |  |  | $ | — |
Net loss attributed to common stockholders |  | $ | (654,545 | ) |  | $ | (803,692 | ) |  | $ | (425,703 | )
Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock |  |  | 195,021 |  |  |  | 188,013 |  |  |  | 203,039 |
Basic loss from continuing operations per common share |  | $ | (3.37 | ) |  | $ | (4.27 | ) |  | $ | (2.10 | )
Basic income from discontinued operations per common share |  | $ | 0.01 |  |  | $ | — |  |  | $ | — |
Basic net loss per common share |  | $ | (3.36 | ) |  | $ | (4.27 | ) |  | $ | (2.10 | )
DILUTED EPS: |  |  |  |  |  |  |  |  |
Net loss from continuing operations attributed to common stockholders |  | $ | (657,079 | ) |  | $ | (803,692 | ) |  | $ | (425,703 | )
Net income from discontinued operations attributed to common stockholders |  | $ | 2,534 |  |  | $ | — |  |  | $ | — |
Net loss attributed to common stockholders |  | $ | (654,545 | ) |  | $ | (803,692 | ) |  | $ | (425,703 | )
Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock |  |  | 195,021 |  |  |  | 188,013 |  |  |  | 203,039 |
Diluted loss from continuing operations per common share |  | $ | (3.37 | ) |  | $ | (4.27 | ) |  | $ | (2.10 | )
Diluted income from discontinued operations per common share |  | $ | 0.01 |  |  | $ | — |  |  | $ | — |
Diluted net loss per common share |  | $ | (3.36 | ) |  | $ | (4.27 | ) |  | $ | (2.10 | )
Potentially dilutive securities excluded as anti-dilutive |  |  | 9,551 |  |  |  | 8,747 |  |  |  | 9,195 |

16. Employee Benefits

We maintain a 401(k) plan for all eligible employees. Our operating results include expenses of approximately $7.6 million in 2021, $7.7 million in 2020 and $13.2 million in 2019 for our contributions to the plan.

17. Business Segments

At December 31, 2021, we had three reportable business segments: (i) contract drilling of oil and natural gas wells, (ii) pressure pumping services and (iii) directional drilling services. Each of these segments represents a distinct type of business and has a separate management team that reports to our chief operating decision maker. The results of operations in these segments are regularly reviewed by the chief operating decision maker for purposes of determining resource allocation and assessing performance. We also disclose our identifiable assets for these segments, which are primarily comprised of long-lived assets.

Contract Drilling — We market our contract drilling services to major and independent oil and natural gas operators. As of December 31, 2021, we had 184 marketed land-based drilling rigs in the continental United States and eight in Colombia.

Our acquisition of Pioneer in 2021 expanded our geographic footprint into Latin America with the addition of eight SCR drilling rigs in Colombia. Our revenues and direct operating costs for our Colombian operations are included as part of our contract drilling segment.

F-34

For the year ended December 31, 2021, contract drilling revenue earned in Colombia was $15.8 million. Additionally, long-lived assets for the contract drilling segment recorded as part of our Colombian operations totaled $39.3 million as of December 31, 2021.

Pressure Pumping — We provide pressure pumping services to oil and natural gas operators primarily in Texas and the Appalachian region. Substantially all of the revenue in the pressure pumping segment is from well stimulation services (such as hydraulic fracturing) for the completion of new wells and remedial work on existing wells. Well stimulation involves processes inside a well designed to enhance the flow of oil, natural gas, or other desired substances from the well. We also provide cementing services through our pressure pumping segment. Cementing is the process of inserting material between the wall of the well bore and the casing to support and stabilize the casing.

Directional Drilling — We provide a comprehensive suite of directional drilling services in most major producing onshore oil and gas basins in the United States. Substantially all of the revenue in the directional drilling segment is from directional drilling, downhole performance motors and measurement-while-drilling services, which are sold as a bundle.

Major Customer — During 2021, one customer accounted for approximately $216 million or 16% of our consolidated operating revenues. These revenues in 2021 were earned in both our contract drilling and pressure pumping businesses. During 2020 and 2019 no single customer accounted for more than 10% of our consolidated operating revenues.

F-35

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

|  | Year Ended December 31, |
|  | 2021 |  |  | 2020 |  |  | 2019 |
Revenues: |  |  |  |  |  |  |  |  |
Contract drilling |  | $ | 667,918 |  |  | $ | 670,357 |  |  | $ | 1,309,988 |
Pressure pumping |  |  | 523,756 |  |  |  | 336,111 |  |  |  | 868,694 |
Directional drilling |  |  | 111,481 |  |  |  | 73,356 |  |  |  | 188,786 |
Other operations (1) |  |  | 75,505 |  |  |  | 57,962 |  |  |  | 122,885 |
Elimination of intercompany revenues - Contract drilling (2) |  |  | (3,888 | ) |  |  | (1,231 | ) |  |  | (1,638 | )
Elimination of intercompany revenues - Other operations (2) |  |  | (17,691 | ) |  |  | (12,306 | ) |  |  | (18,030 | )
Total revenues |  | $ | 1,357,081 |  |  | $ | 1,124,249 |  |  | $ | 2,470,685 |
Income (loss) before income taxes: |  |  |  |  |  |  |  |  |
Contract drilling |  | $ | (423,029 | ) |  | $ | (543,438 | ) |  | $ | (151,329 | )
Pressure pumping |  |  | (118,863 | ) |  |  | (166,666 | ) |  |  | (102,701 | )
Directional drilling |  |  | (35,301 | ) |  |  | (40,612 | ) |  |  | (52,724 | )
Other operations |  |  | (9,905 | ) |  |  | (41,685 | ) |  |  | (54,725 | )
Corporate |  |  | (92,152 | ) |  |  | (94,251 | ) |  |  | (94,414 | )
Credit loss expense |  |  | 1,500 |  |  |  | (5,606 | ) |  |  | (5,683 | )
Interest income |  |  | 222 |  |  |  | 1,254 |  |  |  | 6,013 |
Interest expense |  |  | (41,978 | ) |  |  | (40,770 | ) |  |  | (75,204 | )
Other |  |  | (275 | ) |  |  | 756 |  |  |  | 389 |
Loss before income taxes |  | $ | (719,781 | ) |  | $ | (931,018 | ) |  | $ | (530,378 | )
Depreciation, depletion, amortization and impairment: |  |  |  |  |  |  |  |  |
Contract drilling |  | $ | 618,879 |  |  | $ | 433,771 |  |  | $ | 668,007 |
Pressure pumping |  |  | 159,305 |  |  |  | 152,630 |  |  |  | 233,952 |
Directional drilling |  |  | 40,270 |  |  |  | 36,504 |  |  |  | 52,223 |
Other operations |  |  | 24,865 |  |  |  | 41,511 |  |  |  | 42,803 |
Corporate |  |  | 5,859 |  |  |  | 6,494 |  |  |  | 6,888 |
Total depreciation, depletion, amortization and impairment |  | $ | 849,178 |  |  | $ | 670,910 |  |  | $ | 1,003,873 |
Capital expenditures: |  |  |  |  |  |  |  |  |
Contract drilling |  | $ | 109,894 |  |  | $ | 105,037 |  |  | $ | 194,416 |
Pressure pumping |  |  | 34,676 |  |  |  | 21,678 |  |  |  | 105,803 |
Directional drilling |  |  | 8,591 |  |  |  | 4,681 |  |  |  | 15,549 |
Other operations |  |  | 11,638 |  |  |  | 12,378 |  |  |  | 27,132 |
Corporate |  |  | 1,521 |  |  |  | 1,707 |  |  |  | 4,612 |
Total capital expenditures |  | $ | 166,320 |  |  | $ | 145,481 |  |  | $ | 347,512 |
Identifiable assets: |  |  |  |  |  |  |  |  |
Contract drilling |  | $ | 2,169,501 |  |  | $ | 2,315,318 |  |  | $ | 3,190,463 |
Pressure pumping |  |  | 458,202 |  |  |  | 486,702 |  |  |  | 695,570 |
Directional drilling |  |  | 87,285 |  |  |  | 107,807 |  |  |  | 164,273 |
Other operations |  |  | 85,932 |  |  |  | 88,676 |  |  |  | 128,290 |
Corporate (3) |  |  | 156,928 |  |  |  | 300,566 |  |  |  | 261,019 |
Total assets |  | $ | 2,957,848 |  |  | $ | 3,299,069 |  |  | $ | 4,439,615 |

(1)
Other operations includes our oilfield rentals business, drilling equipment service business, the electrical controls and automation business and the oil and natural gas working interests.
(2)
Intercompany revenues consist of revenues from contract drilling for services provided to our other operations, and revenues from other operations for services provided to contract drilling, pressure pumping and within other operations. These revenues are generally based on estimated external selling prices and are eliminated during consolidation.
(3)
Corporate assets primarily include cash on hand and certain property and equipment.

F-36

18. Concentrations of Credit Risk

Financial instruments which potentially subject us to concentrations of credit risk consist primarily of demand deposits, temporary cash investments and trade receivables.

We believe we have placed our demand deposits and temporary cash investments with high credit-quality financial institutions. At December 31, 2021 and 2020, our demand deposits and temporary cash investments consisted of the following (in thousands):

|  | 2021 |  |  | 2020 |
Deposits in FDIC and SIPC-insured institutions under insurance limits |  | $ | 2,043 |  |  | $ | 1,000 |
Deposits in FDIC and SIPC-insured institutions over insurance limits |  |  | 125,405 |  |  |  | 227,961 |
Deposits in foreign banks |  |  | 9,342 |  |  |  | 1,966 |
|  |  | 136,790 |  |  |  | 230,927 |
Less outstanding checks and other reconciling items |  |  | (19,266 | ) |  |  | (6,012 | )
Cash and cash equivalents |  | $ | 117,524 |  |  | $ | 224,915 |

Concentrations of credit risk with respect to trade receivables are primarily focused on companies involved in the exploration and development of oil and natural gas properties. The concentration is somewhat mitigated by the diversification of customers for which we provide services. As is general industry practice, we typically do not require customers to provide collateral. A $5.6 million provision for credit loss was recognized in 2020 in relation to accounts receivable balances that were estimated to be uncollectible. During 2021, we reversed $1.5 million of our credit loss provision related to certain customers who had previously experienced a deterioration in credit quality. Since initially recording loss provisions for these receivables, we have collected portions of the accounts that were deemed uncollectible.

19. Fair Values of Financial Instruments

The carrying values of cash and cash equivalents, trade receivables and accounts payable approximate fair value due to the short-term maturity of these items. These fair value estimates are considered Level 1 fair value estimates in the fair value hierarchy of fair value accounting.

The estimated fair value of our outstanding debt balances as of December 31, 2021 and 2020 is set forth below (in thousands):

|  | December 31, 2021 |  |  | December 31, 2020 |
|  | Carrying |  |  | Fair |  |  | Carrying |  |  | Fair |
|  | Value |  |  | Value |  |  | Value |  |  | Value |
3.95% Senior Notes |  | $ | 509,505 |  |  | $ | 511,652 |  |  | $ | 509,505 |  |  | $ | 471,019 |
5.15% Senior Notes |  |  | 349,250 |  |  |  | 359,142 |  |  |  | 349,250 |  |  |  | 319,560 |
Term Loan Agreement |  |  | — |  |  |  | — |  |  |  | 50,000 |  |  |  | 50,000 |
Total debt |  | $ | 858,755 |  |  | $ | 870,794 |  |  | $ | 908,755 |  |  | $ | 840,579 |

The fair values of the 3.95% Senior Notes and the 5.15% Senior Notes at December 31, 2021 and December 31, 2020 are based on quoted market prices, which are considered Level 1 fair value estimates in the fair value hierarchy of fair value accounting. The fair values of the 3.95% Senior Notes implied a 3.87% market rate of interest at December 31, 2021 and the 5.24% market rate of interest at December 31, 2020, based on their quoted market prices. The fair values of the 5.15% Senior Notes implied a 4.72% market rate of interest at December 31, 2021 and the 6.42% market rate of interest at December 31, 2020, based on their quoted market prices. T he carrying value of the balance outstanding at December 31, 2020 under the Term Loan Agreement approximated its fair value as the instrument had a floating interest rate.

20. Restructuring Expenses

During the second quarter of 2020, we implemented a restructuring plan to improve operating margins, achieve operational efficiencies and reduce indirect support costs. The restructuring included workforce reductions, changes to management structure and facility consolidations and closures. We recorded $38.3 million of charges associated with this plan in the second quarter of 2020. T here were no restructuring charges in the comparable periods of 2021 or 2019. We completed the restructuring plan during the third quarter of 2020 and did not incur additional expenses related to the plan.

Contract termination costs related primarily to agreements to purchase minimum quantities of proppants (sand) from certain vendors. These costs were primarily comprised of a $5.3 million negotiated settlement and termination of a contract to purchase minimum quantities of sand and $14.0 million of contractual future payments under two contracts to purchase minimum quantities of sand without future economic benefit to us. We will not receive any sand under these contracts. Other exit costs related primarily to facility closure costs and moving expenses.

F-37

The right-of-use asset abandonments related to facility and equipment right-of-use assets abandoned as a result of restructuring.

The following table presents restructuring expenses by reportable segment f or the year ended December 31, 2020 (in thousands):

|  | Contract Drilling |  |  | Pressure Pumping |  |  | Directional Drilling |  |  | Other Operations |  |  | Corporate |  |  | Total |
Severance costs |  | $ | 1,821 |  |  | $ | 3,460 |  |  | $ | 503 |  |  | $ | 501 |  |  | $ | 215 |  |  | $ | 6,500 |
Contract termination costs |  |  | — |  |  |  | 20,373 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 20,373 |
Other exit costs |  |  | 523 |  |  |  | 194 |  |  |  | 827 |  |  |  | — |  |  |  | — |  |  |  | 1,544 |
Right-of-use asset abandonments |  |  | 86 |  |  |  | 7,304 |  |  |  | 1,845 |  |  |  | — |  |  |  | 686 |  |  |  | 9,921 |
Total |  | $ | 2,430 |  |  | $ | 31,331 |  |  | $ | 3,175 |  |  | $ | 501 |  |  | $ | 901 |  |  | $ | 38,338 |

F-38

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

S CHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

|  |  |  |  | Charged to |  |  |  |  |  |  |
|  | Beginning |  |  | Costs and |  |  |  |  |  | Ending |
Description |  | Balance |  |  | Expenses |  |  | Deductions (1) |  |  | Balance |
|  | (In thousands) |
Year Ended December 31, 2021 |  |  |  |  |  |  |  |  |  |  |  |
Deducted from asset accounts: |  |  |  |  |  |  |  |  |  |  |  |
Allowance for credit losses |  | $ | 10,842 |  |  | $ | (1,500 | ) |  | $ | (849 | ) |  | $ | 8,493 |
Year Ended December 31, 2020 |  |  |  |  |  |  |  |  |  |  |  |
Deducted from asset accounts: |  |  |  |  |  |  |  |  |  |  |  |
Allowance for credit losses |  | $ | 6,516 |  |  | $ | 5,606 |  |  | $ | (1,280 | ) |  | $ | 10,842 |
Year Ended December 31, 2019 |  |  |  |  |  |  |  |  |  |  |  |
Deducted from asset accounts: |  |  |  |  |  |  |  |  |  |  |  |
Allowance for credit losses |  | $ | 2,312 |  |  | $ | 5,683 |  |  | $ | (1,479 | ) |  | $ | 6,516 |

(1)
Consists of uncollectible accounts written-off.

S-1

SIGNATURES

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

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

Date: February 16, 2022

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 16, 2022.

Signature |  | Title
/s/ Curtis W. Huff |  | Chairman of the Board
Curtis W. Huff |  |
/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/ Tiffany Thom Cepak |  | Director
Tiffany Thom Cepak |  |
/s/ Michael W. Conlon |  | Director
Michael W. Conlon |  |
/s/ Terry H. Hunt |  | Director
Terry H. Hunt |  |
/s/ Janeen S. Judah |  | Director
Janeen S. Judah |  |

S-2