| UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, DC 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 001-37988
NexTier Oilfield Solutions Inc.
(Exact Name of Registrant as Specified in its Charter)
| Delaware | 38-4016639 | ||||||||||
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | ||||||||||
| 3990 Rogerdale Rd | Houston | Texas | 77042 | ||||||||
| (Address of principal executive offices) | (Zip code) | ||||||||||
(713) 325-6000
(Registrant’s telephone number, including area code)
| Securities registered pursuant to Section 12(b) of the Act: | ||||||||
| Title of Each Class | Trading Symbol | Name of Each Exchange On Which Registered | ||||||
| Common Stock, $0.01 par value | NEX | New York Stock Exchange | ||||||
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 ☒ 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 ☐ 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 ☒ 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 | ☐ | ||||||||
| Non-accelerated filer | ☐ | Smaller reporting company | ☐ | ||||||||
| Emerging growth company | ☐ | ||||||||||
If an emerging growth company, indicate by check mark if the registrant has elected to not 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 Exchange Act). Yes ☐ No ☒
The aggregate market value of the common stock of the registrant held by non-affiliates of the registrant, computed by reference to the price at which the common stock was last sold on June 30, 2021, was approximately $818.5 million.
As of February 18, 2022, the registrant had 243,794,695 shares of common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive proxy statement for its 2022 Annual Meeting of Stockholders, which will be filed with the United States Securities and Exchange Commission within 120 days of December 31, 2021, are incorporated by reference into Part III of this Annual Report on Form 10-K.
Auditor Name: KPMG LLP Auditor Location: Houston, Texas Auditor Firm ID: 185
TABLE OF CONTENTS
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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS AND INFORMATION
This Annual Report on Form 10-K contains forward-looking statements, within the meaning of the Private Securities Litigation Reform Act of 1995, which are subject to risks and uncertainties. All statements other than statements of historical facts contained in this Annual Report on Form 10-K, including statements regarding our future operating results and financial position, business strategy and plans and objectives of management for future operations, are forward-looking statements. Our forward-looking statements are generally accompanied by words such as “may,” “should,” “expect,” “believe,” “plan,” “anticipate,” “could,” “intend,” “target,” “goal,” “project,” “contemplate,” “estimate,” “predict,” “potential,” “outlook,” “reflect,” “forecast,” “future,” or “continue” or the negative of these terms or other similar expressions. Any forward-looking statements contained in this Annual Report on Form 10-K speak only as of the date on which we make them and are based upon our historical performance and on current plans, estimates and expectations. Except as required by law, we have no obligation to update any forward-looking statements made in this Annual Report on Form 10-K to reflect events or circumstances after the date of this Annual Report on Form 10-K or to reflect new information or the occurrence of unanticipated events. Forward-looking statements contained in this Annual Report on Form 10-K include, but are not limited to, statements about:
• the continued impact of the COVID-19 pandemic (including as a result of the emergence of new variants and strains of the virus, such as Delta and Omicron) and the evolving response thereto by governments, private businesses or others to contain the spread of the virus and its variants or to treat its impact;
• changing regional, national or global economic conditions, including oil and gas supply and demand;
• our business strategy;
• our plans, objectives, expectations and intentions;
• the competitive nature of the industry in which we conduct our business, including pricing pressures;
• our future operating results;
• crude oil and natural gas commodity prices;
• demand for services in our industry;
• the impact of pipeline and storage capacity constraints;
• the impact of adverse weather conditions;
• the effects of government regulation;
• changes in tax laws;
• legal proceedings, liability claims and effect of external investigations;
• the effect of a loss of, or the financial distress of, one or more customers;
• our ability to obtain or renew customer contracts;
• the effect of a loss of, or interruption in operations of, one or more key suppliers;
• our ability to maintain the right level of commitments under our supply agreements;
• the market price and availability of materials or equipment;
• the impact of new technology;
• our ability to employ a sufficient number of skilled and qualified workers;
• our ability to obtain permits, approvals and authorizations from governmental and third parties;
• planned acquisitions, divestitures and future capital expenditures;
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• our ability to maintain effective information technology systems;
• our ability to maintain an effective system of internal controls over financial reporting;
• our ability to service our debt obligations;
• financial strategy, liquidity or capital required for our ongoing operations and acquisitions, and our ability to raise additional capital;
• the market volatility of our stock;
• our ability or intention to pay dividends or to effectuate repurchases of our common stock;
• the impact of ownership by Cerberus (through Keane Investor); and
• the impact of our corporate governance structure.
We caution you that the foregoing list may not contain all of the forward-looking statements made in this Annual Report on Form 10-K.
You should not rely upon forward-looking statements as predictions of future events. We have based the forward-looking statements contained in this Annual Report on Form 10-K primarily on our current expectations and projections about future events and trends that we believe may affect our business, financial condition, results of operations and prospects. The outcome of the events described in these forward-looking statements is subject to risks, uncertainties and other factors described in the section entitled Part I, “Item 1A. Risk Factors” and elsewhere in this Annual Report on Form 10-K. Moreover, we operate in a very competitive and rapidly changing environment. New risks and uncertainties emerge from time to time, and it is not possible for us to predict all risks and uncertainties that could have an impact on the forward-looking statements contained in this Annual Report on Form 10-K. We cannot assure you that the results, events, circumstances, plans, intentions or expectations reflected in any forward-looking statements will be achieved or occur. Actual results, events or circumstances could differ materially from those described in such forward-looking statements, and you should not place undue reliance on our forward-looking statements. Our forward-looking statements do not reflect the potential impact of any future acquisitions, mergers, dispositions, joint ventures or investments we may make. We undertake no obligation to revise or update any forward-looking statements for any reason, except as required by law.
This Annual Report on Form 10-K includes market and industry data and certain other statistical information based on third-party sources including independent industry publications, government publications and other published independent sources. Although we believe these third-party sources are reliable as of their respective dates, we have not independently verified the accuracy or completeness of this information. Some data is also based on our own good faith estimates, which are supported by our management’s knowledge of and experience in the markets and businesses in which we operate.
While we are not aware of any misstatements regarding any market, industry or similar data presented herein, such data involves risks and uncertainties and is subject to change based on various factors, including those discussed above and in Part 1, “Item 1A. Risk Factors” in this Annual Report on Form 10-K.
References Within This Annual Report
As used in this Annual Report on Form 10-K, unless the context otherwise requires, references to (i) the terms “Company,” “NexTier,” “we,” “us” and “our” refer to NexTier Oilfield Solutions Inc. and its consolidated subsidiaries; (ii) the term “Keane Group” refers to Keane Group Holdings, LLC and its consolidated subsidiaries; (iii) the term “RSI” refers to Refinery Specialties, Incorporated; (iv) the term “Keane Investor” refers to Keane Investor Holdings LLC; (v) the term “Cerberus” refers to Cerberus Capital Management, L.P. and its controlled affiliates and investment funds; (vi) the term “C&J” refers to C&J Energy Services, Inc.; (vii) the term “C&J Merger” refers to the consummation of the transactions described in that certain Agreement and Plan of Merger, dated as of June 16, 2019, by and among the C&J, us and King Merger Sub Corp., one of our wholly owned subsidiaries; (viii) the term “Alamo” refers to Alamo Pressure Pumping, LLC and its wholly owned subsidiaries; and (ix) the term “Alamo Acquisition” refers to the consummation of the transactions described in that certain Purchase agreement (the “Purchase Agreement”), by and among the Company and Alamo Frac Holdings, LLC.
As used in this Annual Report on Form 10-K, capacity in the hydraulic fracturing business refers to the total number of hydraulic horsepower, regardless of whether such hydraulic horsepower is active and deployed, active and not
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deployed or inactive. While the equipment and amount of hydraulic horsepower required for a customer project varies, we calculate our total number of fleets, as used in this Annual Report on Form 10-K, by dividing our total hydraulic horsepower by approximately 63,000 hydraulic horsepower.
As used in this Annual Report on Form 10-K, references to cannibalization of parked equipment refer to the removal of parts and components (such as the engine or transmission of a fracturing pump) from an idle hydraulic fracturing fleet in order to service an active hydraulic fracturing fleet.
BASIS OF PRESENTATION IN THIS ANNUAL REPORT ON FORM 10-K
The consolidated financial statements for the period from January 1, 2019 to October 31, 2019 reflect only the historical results of the Company prior to the completion of the C&J Merger. The financial statements have been prepared using the acquisition method of accounting under existing United States (“U.S.”) Generally Accepted Accounting Principals (“GAAP”), which requires that one of the two companies in the C&J Merger be designated as the acquirer for accounting purposes. C&J and Keane determined that Keane was the accounting acquirer. Accordingly, consideration given by Keane to complete the C&J Merger was allocated to the underlying tangible and intangible assets and liabilities acquired based on their estimated fair values as of the date of completion of the C&J Merger, with any excess purchase price allocated to goodwill.
The condensed consolidated financial statements for the period from January 1, 2019 to August 31, 2021 reflect only the historical results of the Company prior to the completion of the Alamo Acquisition.
For further details, see Note (1) Basis of Presentation and Nature of Operations of Part II, “Item 8. Financial Statements and Supplemental Data.” For more details regarding the C&J Merger and the Alamo Acquisition, refer to Note (3) Mergers and Acquisitions.
All information presented herein is based on our fiscal calendar. Unless otherwise stated, references to particular years, quarters, months or periods refer to our fiscal years and the associated quarters, months and periods of those fiscal years.
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PART I
Item 1. Business
General description of the business
NexTier Oilfield Solutions Inc. is a predominately U.S. land focused oilfield service company, with a diverse set of well completion and production services across a variety of active and demanding basins. We provide our services through our operating subsidiaries to exploration and production (“E&P”) customers. Our integrated solutions approach is focused on delivering efficiency, and our ongoing commitment to innovation helps our customers capitalize on technological advancements. NexTier is differentiated through four points of distinction, including safety performance, efficiency, partnership and innovation.
We were formed under the name Keane Group, Inc. as a Delaware corporation on October 13, 2016, to be a holding corporation as part of an organizational restructuring of Keane Group Holdings, LLC, which was formed March 1, 2011, and its subsidiaries, for the purpose of facilitating the initial public offering of shares of common stock of the Company in 2017. On January 25, 2017, we consummated an initial public offering (“IPO”). To effectuate the IPO, we completed a series of transactions reorganizing our business, resulting in the Company being a holding company with no material assets other than its ownership of Keane Group. In connection with the restructuring, the Keane Group entities became wholly owned subsidiaries of the Company.
On October 31, 2019, we completed a merger transaction with C&J Energy Services, Inc., a publicly traded Delaware corporation. Pursuant to this transaction, C&J was ultimately merged with and into our wholly owned merger subsidiary, with our subsidiary continuing as the surviving entity. On the effective date of the C&J Merger, we changed our name to “NexTier Oilfield Solutions Inc.” Since 2013, our growth through acquisition strategy has resulted in the growth of the location and scale of our operational footprint, expansion of our customer base, addition of wireline operations, increase in our pumping capacity and expansion of our hydraulic fracturing operations by more than an additional 2.1 million hydraulic horsepower.
In March of 2020, we divested the legal entities and the majority of the assets that comprised our Well Support Services segment. We are currently organized into two reportable segments, consisting of:
•Completion Services, which consists of the following business lines: (1) fracturing services; (2) wireline and pumping services; and (3) completion support services, which includes our research and technology (“R&T”) department; and
•Well Construction and Intervention Services (“WC&I”), which consists of the following business lines: (1) cementing services and (2) coiled tubing services.
On August 31, 2021, we completed the acquisition of Alamo Pressure Pumping, LLC and its wholly owned subsidiaries.
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Completion Services segment
Our completion services are designed in partnership with our customers to enhance both initial production rates and estimated ultimate recovery from new and existing wells. The core services provided through our Completion Services segment are hydraulic fracturing, wireline and pumping services. We utilize our in-house capabilities, including our R&T department and data control instruments business, to offer a technologically advanced and efficiency focused range of completion techniques. The majority of revenue for this segment is generated by our fracturing business.
Hydraulic Fracturing. Hydraulic fracturing services are performed to enhance production of oil and natural gas from formations with low permeability and restricted flow of hydrocarbons. The process of hydraulic fracturing involves pumping a highly viscous, pressurized fracturing fluid, typically a mixture of water, chemicals and proppant, into a well casing or tubing in order to fracture underground mineral formations. These fractures release trapped hydrocarbon particles and free a channel for the oil or natural gas to flow freely to the wellbore for collection. Fracturing fluid mixtures include proppant that becomes lodged in the cracks created by the hydraulic fracturing process, “propping” them open to facilitate the flow of hydrocarbons upward through the well. In late 2020, we began evolving our completion service offerings to develop an integrated natural gas treatment and delivery solution. In 2021, we launched our new Power Solutions business, which focuses on gas sourcing, compression, transport, decompression, treatment and related services for our fracturing operations. We believe this integration solution will assist our customers to reduce emissions at the wellsite and throughout their operations.
Wireline Technologies. Our wireline services involve the use of a truck equipped with a spool of wireline that is unwound and lowered into oil and natural gas wells to convey specialized tools or equipment for well completion, well intervention, pipe recovery and reservoir evaluation purposes. We offer our wireline services in conjunction with our hydraulic fracturing services in “plug-and-perf” well completions to maximize efficiency for our customers. “Plug-and-perf” is a multi-stage well completion technique for cased-hole wells that consists of pumping a plug and perforating guns to a specified depth. Once the plug is set, the zone is perforated and the tools are removed from the well, a ball is pumped down to isolate the zones below the plug and the hydraulic fracturing treatment is applied.
In addition, we offer wireline and pumping services that are not integrated with our fracturing services. We are one of the leading providers of perforating, pumpdown, pipe recovery, pressure pumping, and wellsite make-up and pressure testing services. We are highly experienced in safely servicing deep, high-pressure, high-temperature wells in some of the most active onshore basins in the United States. Our in-house manufacturing capabilities through our R&T department allow us to manage costs and lead times with regard to hardware and perforating guns, switches and accessories, providing us with a competitive advantage and enabling higher returns.
Well Construction and Intervention Services segment
Cementing. Our cementing services incorporate custom engineered mixing and blending equipment to ensure precision and accuracy in providing annulus isolation and hydraulic seal, while protecting fresh water zones from our customers’ zone of interest. Our cement division has the expertise to cement shallow to complex high temperature, high pressure wells. We also offer engineering software and technical guidance for remedial cementing applications and acidizing to optimize the performance of our customers’ wells. We are one of the largest providers of specialty cementing services in the United States. Our operations are supported by multiple full-service laboratory facilities with advanced capabilities.
Coiled Tubing. We offer a broad range of coiled tubing services to help customers accomplish a wide variety of goals in their horizontal completion, workover and well maintenance projects. The majority of our coiled tubing fleet consists of large diameter coil, meaning two inches or larger in diameter, which allows us to service wells with longer lateral lengths. Our coiled tubing services allow customers to complete projects quickly and safely across a wide spectrum of pressures, without having to shut in their wells.
Well Support Services segment
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On March 9, 2020 we sold our Well Support Services Segment. For additional information on this transaction, see Note (21) Business Segments of Part II, “Item 8. Financial Statements and Supplemental Data.” Prior to the sale, our Well Support Services segment focused on post-completion activities at the well site, and includes rig services, such as workover, fluids management, and other specialty well site services. The majority of revenue for this segment was generated by our rig services business, and we considered our rig services and fluids management businesses to be our primary service lines within this reportable segment.
Rig Services. As part of our services that helped prolong the productive life of an oil or gas well, we operated one of the largest rig fleets in the United States. These rigs were involved in the routine repair and maintenance of oil and gas wells, re-drilling operations and plug and abandonment operations. Our rig fleet was also used in the process of permanently shutting-in oil or gas wells that were at the end of their productive lives.
Fluids Management. We provided a full range of fluid services, including the storage, transportation and disposal of various fluids used in various phases including drilling, completion and workover of oil and gas wells. Our fleet of trucks and trailers and portable tanks enabled us to rapidly deploy our equipment across a broad geographic area.
Business strategy
As part of our integration under the NexTier name, introspection by the resulting management team refined our business mission as one to responsibly grow and continuously improve our business in a way that maximizes stockholder value by taking care of our people, our customers, our communities and the environment. Our principal business objective is to deliver integrated, environmentally conscious completion services and power solutions that help enable our customers to safely and affordably unlock sources of energy. We believe that by successfully deploying this strategy, we can deliver industry leading returns and increase stockholder value. We maintain a strict focus on health, safety and environmental stewardship and cost-effective customer-centric solutions. We expect to achieve this objective through:
•developing and expanding our relationships with existing and new customers;
•continuing our exemplary safety performance;
•investing further in driving efficiencies and environmental stewardship, including through our digital platform and evolving power solutions offering;
•maintaining a conservative balance sheet to preserve operational and strategic flexibility; and
•continuing to evaluate potential consolidation opportunities that strengthen our capabilities, increase our scale and create stockholder value.
For further discussion on the business strategies we plan to continue executing in 2022, see Part II, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
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Customers
Our customers primarily include major integrated and large independent oil and natural gas E&P companies. For the year ended December 31, 2021, revenue from one customer individually represented approximately 14% of the Company’s consolidated revenue. This customer represented $193.4 million of our consolidated revenue in the Completions Services segment. For the year ended December 31, 2020, two customers individually represented more than 10% and collectively represented 29% of the Company’s consolidated revenue. These two customers represented $188.6 million and $160.5 million, respectively, of our consolidated revenue in the Completions Services segment. For the year ended December 31, 2019, four customers individually represented more than 10% and collectively represented 55% of the Company’s consolidated revenue. These four customers represented $346.9 million, $242.1 million, $213.4 million, and $194.7 million, respectively, of our consolidated revenue in the Completions Services segment.
Competition and Sales
The markets in which we operate are highly competitive with significant potential for excess capacity. Projects are often awarded on a bid basis, which tends to increase the highly competitive nature of the environment in which we operate. We provide services in various geographic regions, predominately across the U.S., and the competitive landscape varies in each. Utilization and pricing for our services have, from time to time, been negatively affected by increases in supply relative to demand in our operating areas and geographic markets. This was exacerbated in 2020 and 2021 due to the COVID-19 pandemic and other oil and gas market drivers. See additional discussion in Part II, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”. Our major competitors for both our Completions Services and Well Construction and Intervention Services segments include Halliburton Company, Liberty Oilfield Services Inc., Patterson-UTI Energy, Inc., ProPetro Services, Inc., RPC, Inc., ProFrac Services, and U.S. Well Services. We also compete regionally in each segment with a significant number of smaller service providers.
Historically, our core competitive factors in the markets we serve have been our multi-basin service capability and close proximity to our customers, technical expertise, equipment reliability, work force competency, efficiency, safety record, reputation, experience and prices. While these factors continue to dominate, we believe that our customers have begun to look beyond these core requirements to prefer suppliers that can provided integrated solutions that align the incentives of operators and service providers.
While we seek to be competitive in our pricing, we believe many of our customers have elected to work with us based on our customer-tailored partnership approach, our safety record, the performance and competency of our crews and the quality of our equipment and our services. We seek to differentiate ourselves from our competitors by delivering the highest-quality services and equipment possible, coupled with superior execution and operating efficiency, resulting in cost effective operations and a safe working environment. NexTier has also been developing and building its digital program for some time. We believe our digital program, continued investment in diesel substitution (such as duel fuel capabilities), and our integrated natural gas treatment and delivery solution are important to achieving emissions reductions initiatives, both for us and our customers, and provide a competitive differentiating factor.
Raw materials
We purchase a wide variety of raw materials, parts and components that are manufactured and supplied for our operations. We are not dependent on any single source of supply for those parts, supplies or materials. To date, we have generally been able to obtain the equipment, parts and supplies necessary to support our operations on a timely basis. While we believe we will be able to make satisfactory alternative arrangements in the event of any interruption in the supply of these materials and/or products by one of our suppliers, this may not always be the case. In addition, certain materials for which we do not currently have long-term supply agreements could experience shortages and significant price increases in the future.
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For the year ended December 31, 2021, purchases from our largest supplier represented approximately 5% of the Company’s overall purchases.
Research & technology and intellectual property
We have invested in technological advancement, including the development of a state-of-the-art innovation center staffed by a team of highly skilled digital professionals and engineers. Our innovation efforts have been focused on fit-for-purpose solutions designed to enhance our service offerings, increase efficiencies, lower our operating costs, optimize capital expenditures and add value for our customers. This includes developing an innovative digital infrastructure, NexHub, which is an internal, real-time, digital platform that allows around-the-clock remote operations support across the majority of our active fleets. Driven by artificial intelligent logistics and digital operations engineering, NexHub provides key benefits of remote operations to allow for less employees at the well-site, extended equipment life through equipment health monitoring with machine learning and generated alerts, rapid response and adjustment to changing wellsite and equipment conditions, enhanced service quality, and powers data driven decisions.
Our research and development and digital initiatives generate recurring cost savings for our integrated completion services operations, which is central to our overall strategy of proactively managing our costs to maximize returns. Several of these investments provide value-added products and services that, in addition to producing revenue, are creating increasing demand from key customers. In our day-to-day operations, we utilize equipment and products manufactured by our vertically integrated businesses which are managed through our innovation center, and we may also sell such equipment and products to third-party customers in the global energy services industry. We believe that our focus on innovation, with the objective of reducing costs and improving sustainability of our operations, provides a strategic benefit through the ability to fund, develop, and implement new technologies and quickly respond to changes in customer requirements and industry demand.
We own a number of patents and have pending certain patent applications covering various products and services. We are also licensed to utilize technology covered by patents owned by others. Furthermore, we believe the information regarding our customer and supplier relationships are valuable proprietary assets, and we have common law and registered trademarks for various names under which our entities conduct business or provide products or services. We do not own or license any patents, trademarks or other intellectual property that we believe to be material to the success of our business.
Seasonality
Our results of operations have historically reflected seasonal tendencies, generally in the first and fourth quarters, related to the conclusion and restart of our customers’ annual capital expenditure budgets, the holidays and inclement winter weather, during which we may experience declines in our operating results. Our operations in North Dakota and Pennsylvania are particularly affected by seasonality due to inclement winter weather. During the spring and summer months, our operations in certain areas may be impacted by transportation restrictions due to the work-site conditions caused by the spring thaws or tropical weather systems.
Human capital resources
NexTier is committed to conducting our activities in a safe and responsible manner, while fostering a culture to treat every person with respect and dignity. We seek to attract, retain and develop high quality talent who can drive the success of our business while emulating our core values.
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General
As of December 31, 2021, we had 3,340 employees, of which, approximately 82% were compensated on an hourly basis. This was approximately a 70% increase from the 1,969 employees we had on December 31, 2020. Our employees are neither covered by collective bargaining agreements, nor are they members of labor unions. While we consider our relationship with our employees to be satisfactory, disputes may arise over certain classifications of employees that are customary in the oilfield services industry. We are not aware of any other potentially adverse matters involving our employment practices on a company-wide level.
Health and Safety
In our industry, a strong safety record is key to attracting and retaining top-tier customers and employees. We believe we are among the safest service providers in the industry. In 2021, we achieved a total recordable incident rate of 0.84, which is less than the 0.90 incident rate derived from an industry average from 2017 to 2020. We believe total recordable incident rate is a reliable measure of safety performance.
We offer comprehensive health and welfare, disability, and retirement benefits to eligible employees. The core health and welfare benefits are supplemented with discount programs for health-related goods and services, a variety of voluntary benefits and paid time off programs. Health benefits include low-cost telehealth services as well as mental and behavioral health resources, including on-demand access to an Employee Assistance Program for employees and their dependents.
In response to the COVID-19 pandemic, we implemented significant changes that we determined were in the best interest of our employees as well as the communities in which we operate. This includes having the vast majority of our employees work from home for periods of time, while implementing additional safety measures for employees continuing critical on-site work. To maintain minimized exposure points, a flex-work program was developed and deployed in an effort to balance time in the office with remote work from home. To mitigate COVID-19 exposure further pro-active measures have been implemented including, among other things, additional hand sanitizer stations; temperature check kiosks at the entrance to our corporate headquarters; eliminating guests to campuses; shifting all meetings to a virtual format; closing meeting rooms and common/shared areas in the office such as cafeterias and fitness rooms; mandatory face mask wearing (unless the person is eating or alone at work station); installation of signage for CDC guideline distancing and other reminders, and established absence management and tracing protocols to reduce transmission risk. Frequent and consistent communication efforts reinforce the importance of these health and safety measures.
Growth and Development
Hiring, developing and retaining quality employees is important to maximize the success of our operations. We actively foster a learning culture where employees are empowered to drive their career progression, supporting professional development and providing an on-demand learning platform. Competency assessments drive skill development plans and succession plans drive leadership development plans. To further support these objectives, we have designed human resources programs to:
•Enhance the company culture through employee experiences, policies and practices aimed at making the workplace more safe, healthy and inclusive;
•Align leader and team member behaviors to our purpose;
•Facilitate talent acquisition to create a high-performing and diverse workforce;
•Reward employees through competitive pay and benefits;
•Develop employees at all levels through learning strategies focused on new skills required to support operational excellence and advancement within the Company; and
•Evolve and invest in technology and other resources that enable employees to learn and grow more effectively.
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Material government regulation
Our operations are subject to stringent and complex federal, state and local laws, rules and regulations relating to the oil and natural gas industry including the discharge of materials into the environment or otherwise relating to health and safety or the protection of the environment. Numerous governmental agencies, such as the Environmental Protection Agency (the “EPA”), issue regulations to implement and enforce these laws, which often require costly compliance measures. Failure to comply with these laws and regulations may result in the assessment of substantial administrative, civil and criminal penalties, expenditures associated with exposure to hazardous materials, remediation of contamination, property damage and personal injuries, imposition of bond requirements, and restricting permits or other authorizations, as well as the issuance of injunctions limiting or prohibiting our activities. In addition, some laws and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, rendering a person liable for environmental damages and clean-up costs without regard to negligence or fault on the part of that person. Strict compliance with these regulatory requirements increases our cost of doing business and consequently affects our profitability. However, environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements, including those that result in any limitation, suspension or moratorium on the services we provide, whether or not short-term in nature, by federal, state, regional or local governmental authority, could have a material adverse effect on our business, financial condition and results of operations.
The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA” or the “Superfund law”), and comparable state laws impose liability on certain classes of persons that are considered to be responsible for the release of hazardous or other state-regulated substances into the environment. These persons include the current owner or operator of the site and the owner or operator of the site at the time of the release and the parties that disposed or arranged for the disposal or treatment of hazardous or other state-regulated substances that have been released at the site. Under CERCLA, these persons may be subject to strict liability, joint and several liability, or both, for the costs of investigating and cleaning up hazardous substances that have been released into the environment, damages to natural resources and human health without regard to fault. In addition, companies that incur CERCLA liability frequently confront claims by neighboring landowners and other third parties for personal injury and property damage allegedly caused by the release of hazardous or other regulated substances or pollutants into the environment.
The federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976 (“RCRA”), and analogous state laws generally excludes oil and gas exploration and production wastes (e.g., drilling fluids, produced waters) from regulation as hazardous wastes. However, these wastes remain subject to potential regulation as solid wastes under RCRA and as hazardous waste under other state and local laws. Wastes from some of our operations (such as, but not limited to, our chemical development, blending and distribution operations, as well as some maintenance and manufacturing operations) are or may be regulated under RCRA and analogous state laws under certain circumstances. Further, any exemption or regulation under RCRA does not alter treatment of the substance under CERCLA. The impact of future revisions to environmental laws and regulations cannot be predicted. Moreover, stricter standards for waste handling and disposal may be imposed on the oil and natural gas industry in the future. Removal of RCRA’s exemption for exploration and production wastes has the potential to significantly increase waste disposal costs, which in turn will result in increased operating costs and could adversely impact our business and results of operations. Naturally Occurring Radioactive Materials (“NORM”) may contaminate extraction and processing equipment used in the oil and natural gas industry. The waste resulting from such contamination is regulated by federal and state laws. Standards have been developed for: worker protection; treatment, storage, and disposal of NORM and NORM waste; management of NORM-contaminated waste piles, containers and tanks; and limitations on the relinquishment of NORM contaminated land for unrestricted use under RCRA and state laws. It is possible that we may incur costs or liabilities associated with elevated levels of NORM.
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The Federal Water Pollution Control Act (the “Clean Water Act”) and comparable state statutes impose restrictions and strict controls regarding the discharge of pollutants into waters of the United States or state waters. The discharge of pollutants into jurisdictional waters is prohibited unless the discharge is permitted by the EPA or applicable state agencies. The Clean Water Act also prohibits the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Clean Water Act program predictability and consistency have been uncertain for several years due to regulatory changes concerning clarity as to the scope of ‘waters of the United States’ federally regulated under the Act and litigation over those changes. The process for obtaining permits required by the Clean Water Act and analogous state laws has the potential to delay the development of natural gas and oil projects. Also, spill prevention, control and countermeasure regulations imposed under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a hydrocarbon tank spill, rupture or leak.
In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Moreover, the Oil Pollution Act of 1990 (“OPA”) imposes a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages, including natural resource damages, resulting from such spills in waters of the United States. A responsible party includes the owner or operator of an onshore facility. The Clean Water Act and analogous state laws provide for administrative, civil and criminal penalties for unauthorized discharges and, together with the OPA, impose rigorous requirements for spill prevention and response planning, as well as substantial potential liability for the costs of removal, remediation, and damages in connection with any unauthorized discharges.
From time to time, releases of materials or wastes have occurred at locations we own or at which we have operations. These properties and the materials or wastes released thereon may be subject to CERCLA, RCRA, the federal Clean Water Act, the Safe Drinking Water Act (the “SDWA”) and analogous state laws. Under these laws or other laws and regulations, we have been and may be required to remove or remediate these materials or wastes and make expenditures associated with personal injury or property damage. At this time, with respect to any properties where materials or wastes may have been released, it is not possible to estimate the potential costs that may arise from unknown, latent liability risks.
There has been increasing public controversy regarding hydraulic fracturing and its use of fracturing fluids, including potential impacts of the process on drinking water supplies, on the use of water and the potential for impacts to surface water, groundwater and the general environment. Companion bills entitled the Fracturing Responsibility and Awareness of Chemicals Act (“FRAC Act”) were first introduced in the United States Congress in 2009 and successor bills have been reintroduced in the House of Representatives on multiple occasions, most recently in July 2019. The 116th Congress did not act on that legislation before the session adjourned on January 3, 2021; it is possible that a version of the FRAC Act could be introduced for consideration by the 117th Congress. If the FRAC Act and other similar legislation were to pass, the legislation could significantly alter regulatory oversight of hydraulic fracturing. Currently, unless the fracturing fluid used in the hydraulic fracturing process contains diesel fuel, hydraulic fracturing operations are exempt from permitting under the Underground Injection Control (“UIC”) program established by the SDWA but are subject to regulation by state oil and gas commissions. The FRAC Act would remove this exemption and subject hydraulic fracturing operations to permitting requirements under the UIC program. The FRAC Act and other similar bills propose to also require persons conducting hydraulic fracturing to disclose the chemical constituents of their fracturing fluids to a regulatory agency, although they would not require the disclosure of the proprietary formulas except in cases of emergency. Currently, several states require public disclosure of non-proprietary chemicals on FracFocus.org and other equivalent Internet sites. Disclosure of our proprietary chemical formulas to third parties or to the public, even if inadvertent, could diminish the value of those formulas and could result in competitive harm to our business. Moreover, in response to seismic events near underground injection wells used for the disposal of oil and gas-related wastewater, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have imposed volumetric injection limits, shut down or imposed moratoria on the use of such injection wells. At this time, it is not clear what action, if any, the United States Congress will take on the FRAC Act or other related federal and state bills, or the ultimate impact of any such legislation.
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If the FRAC Act or similar legislation becomes law, or the Department of the Interior or another federal agency asserts jurisdiction over certain aspects of hydraulic fracturing operations, additional regulatory requirements could be established at the federal level that could lead to operational delays or increased operating costs, making it more difficult to perform hydraulic fracturing and increasing the costs of compliance and doing business for us and our customers. States in which we operate have considered and may again consider legislation that could impose additional regulations and/or restrictions on hydraulic fracturing operations. At this time, it is not possible to estimate the potential impact on our business of these state actions or the enactment of additional federal or state legislation or regulations affecting hydraulic fracturing.
In addition, at the direction of Congress, the EPA undertook a study of the potential impacts of hydraulic fracturing on drinking water and groundwater and issued its report in December 2016. The EPA report states that there is scientific evidence that hydraulic fracturing activities can impact drinking water resources under some circumstances and identifies certain conditions in which the EPA believes the impact of such activities on drinking water and groundwater can be more frequent or severe. The EPA study could spur further initiatives to regulate hydraulic fracturing under the SDWA or otherwise. Similarly, other federal and state studies may recommend additional requirements or restrictions on hydraulic fracturing operations.
Any regulation that restricts the ability to dispose of produced waters or increases the cost of doing business could cause curtailed or decreased demand for our services and have a material adverse effect on our business. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. If new federal, state or local laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities and make it more difficult or costly to perform hydraulic fracturing. Any such regulations limiting or prohibiting hydraulic fracturing could result in decreased oil and natural gas exploration and production activities and, therefore, adversely affect demand for our services and our business.
The federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed and continues to develop stringent regulations governing emissions of toxic air pollutants from specified sources. We are or may be required to obtain federal and state permits in connection with certain operations conducted in our manufacturing and maintenance facilities. These permits impose certain conditions and restrictions on our operations, some of which require significant expenditures for filtering or other emissions control devices at each of our manufacturing and maintenance facilities. Changes in these requirements, or in the permits we operate under, could increase our costs or limit certain activities. Many of these regulatory requirements, including New Source Performance Standards and Maximum Achievable Control Technology standards, have been made more stringent over time as a result of stricter national ambient air quality standards (“NAAQS”) and other air quality protection goals adopted by the EPA. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant.
Exploration and production activities on federal lands may be subject to review under the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of the Interior, to evaluate major agency actions that have the potential to significantly impact the environment. In the course of such evaluations, an agency—potentially in coordination with other responsible agencies—will prepare an environmental assessment of the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. All of our activities and our customers’ current E&P activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. The NEPA review process has the potential to delay the permitting and subsequent development of oil and natural gas projects.
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Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands and natural resources. These statutes include the Endangered Species Act, the Migratory Bird Treaty Act, the Clean Water Act and CERCLA. Government entities or private parties may act to prevent oil and gas exploration activities or seek damages where harm to species, habitat or natural resources may result from the filling of jurisdictional streams or wetlands, the construction of oil and gas facilities or the release of oil, wastes, hazardous substances or other regulated materials. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. If our customers were to have areas within their business and operations designated as critical or suitable habitat or a protected species, it could decrease demand for our services and have a material adverse effect on our business. At this time, it is not possible to estimate the potential impact on our business of these speculative federal, state or private actions or the enactment of additional federal or state legislation or regulations with respect to these matters.
More stringent laws and regulations relating to climate change may be adopted in the future and could cause us to incur additional operating costs or reduce the demand for our services. The EPA has determined that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to the environment because emissions of such gases are, according to the EPA and many scientists, contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, EPA has adopted regulations that restrict emissions of GHGs under existing provisions of the CAA, including rules that require preconstruction and operating permit reviews for GHG emissions from certain large stationary sources.
The EPA has proposed and finalized a number of rules requiring various industry sectors to track and report, and, in some cases, control greenhouse gas emissions. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified GHG sources, including, among others, certain oil and natural gas production facilities, on an annual basis. Implementation and status of 2016 final rules that establish new air emission controls for emissions of methane from certain equipment and processes in the oil and natural gas source category, including production, processing transmission and storage activities. The EPA’s final rule package included first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas wells. However, regulatory developments to ease or rescind these rules have created uncertainty as to their impact on the oil and gas industry.
While the long-term trajectory of future greenhouse regulations remains unsettled, the current administration has clearly articulated a goal of reducing greenhouse gas emissions and use. For example in January of 2021, President Biden issued an Executive Order that, among other things, declared climate change to be a crisis requiring significant short-term global reduction in greenhouse gas emissions and net-zero global emissions by mid-century or before. The order instructs every government agency to make combatting climate change an essential element of its agenda. In response, in November 2021, EPA proposed further regulation of methane emissions from the oil and gas sector, including new performance standards for certain new and existing sources. In October 2021, the Department of the Interior released a climate adaptation and resilience plan, outlining how it intends to address climate change risks, impacts, and vulnerabilities, including transitioning to a clean energy economy. It is unclear whether Congress will take further action on greenhouse gases, for example, to further regulate greenhouse gas emissions or alternatively to statutorily limit the EPA’s authority over greenhouse gases. However, almost one-half of the states have established or joined GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions or major producers of fuels to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and natural gas industry and, therefore, could reduce the demand for our products and services.
Climate change regulation may also impact our business positively by increasing demand for natural gas for use in producing electricity and as a transportation fuel. Currently, our operations are not materially adversely
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impacted by existing state and local climate change initiatives. At this time, we cannot accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.
We are subject to the requirements of the federal Occupational Safety and Health Act, which is administered and enforced by the Occupational Safety and Health Administration, commonly referred to as OSHA, and of comparable state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and the public. We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances. OSHA continues to evaluate worker safety and to propose new regulations, such as but not limited to, the new rule regarding respirable silica sand, which required the oil and gas industry to implement engineering controls and work practices to limit exposures below the new limits by June 23, 2021.
Among the services we provide, we operate as a motor carrier and therefore are subject to regulation by the United States Department of Transportation (“DOT”) and various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations; regulatory safety; hazardous materials labeling, placarding and marking; financial reporting; and certain mergers, consolidations and acquisitions. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations which govern the amount of time a driver may drive in any specific period and requiring onboard black box recorder devices or limits on vehicle weight and size, and setting minimum training standards for new drivers seeking a commercial driver’s license. Certain motor vehicle operators are required to register with the DOT. This registration requires an acceptable operating record. The DOT periodically conducts compliance reviews and may revoke registration privileges based on certain safety performance criteria, and a revocation could result in a suspension of operations.
Interstate motor carrier operations are subject to safety requirements prescribed by DOT. To a large degree, intrastate motor carrier operations are subject to safety regulations that mirror federal regulations. Such matters as weight and dimensions of equipment are also subject to federal and state regulations. DOT regulations also mandate drug testing of drivers. From time to time, various legislative proposals are introduced, including proposals to increase federal, state or local taxes, including taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted.
Some of our operations utilize equipment that contains sealed, low-grade radioactive sources. Our activities involving the use of radioactive materials are regulated by the United States Nuclear Regulatory Commission (“NRC”) and state regulatory agencies under agreement with the NRC. Standards implemented by these regulatory agencies require us to obtain licenses or other approvals for the use of such radioactive materials. We believe that we have obtained these licenses and approvals as necessary and applicable. Numerous governmental agencies issue regulations to implement and enforce these laws, for which compliance is often costly and difficult. The violation of these laws and regulations may result in the denial or revocation of permits, issuance of corrective action orders, injunctions prohibiting some or all of our operations, assessment of administrative and civil penalties, and even criminal prosecution. In addition, releases of radioactive material could result in substantial remediation costs and potentially expose us to third-party property damage or personal injury claims.
We seek to minimize the possibility of a pollution event through equipment and job design, as well as through training of employees. We also maintain a pollution risk management program that is activated in the event a pollution event occurs. This program includes an internal emergency response plan that provides specific procedures for our employees to follow in the event of a chemical release or spill. In addition, we have contracted
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with several third-party emergency responders in our various operating areas that are available on a 24-hour basis to handle the remediation and clean-up of any chemical release or spill. We carry insurance designed to respond to fortuitous environmental pollution events. This insurance portfolio has been structured in an effort to address pollution incidents that result in bodily injury or property damage and any ensuing clean up required at our owned facilities, as a result of the mobilization and utilization of our fleets, as well as any environmental claims resulting from our operations.
We also seek to manage environmental liability risks through provisions in our contracts with our customers that generally allocate risks relating to surface activities associated with the hydraulic fracturing process, other than water disposal, to us and risks relating to “down-hole” liabilities to our customers. Our customers are responsible for the disposal of the fracturing fluid that flows back out of the well as waste water, for which they use a controlled flow-back process. We are not involved in that process or the disposal of the resulting fluid. Our contracts generally require our customers to indemnify us against pollution and environmental damages originating below the surface of the ground or arising out of water disposal, or otherwise caused by the customer, other contractors or other third parties. In turn, we generally indemnify our customers for pollution and environmental damages originating at or above the surface caused solely by us. We seek to maintain consistent risk-allocation and indemnification provisions in our customer agreements to the extent possible. Some of our contracts, however, contain less explicit indemnification provisions, which typically provide that each party will indemnify the other against liabilities to third parties resulting from the indemnifying party’s actions, except to the extent such liability results from the indemnified party’s gross negligence, willful misconduct or intentional act.
Overall, we do not currently anticipate that compliance with existing environmental laws and regulations will have a material effect on our financial condition or results of operations. It is possible, however, that substantial costs for compliance or penalties for non-compliance may be incurred in the future. Moreover, it is possible that other developments, such as the adoption of stricter environmental laws, regulations, and enforcement policies, could result in additional costs or liabilities that we cannot currently quantify.
Insurance
Our operations are subject to hazards inherent in the oil and natural gas industry, including blowouts, explosions, cratering, fires, oil spills, surface and underground pollution and contamination, hazardous material spills, loss of well control, damage to or loss of the wellbore, formation or underground reservoir, damage or loss from the use of explosives and radioactive materials, and damage or loss from inclement weather or natural disasters. These conditions can cause personal injury or loss of life, damage to or destruction of property, equipment, the environment and wildlife, and interruption or suspension of operations, among other adverse effects. In addition, claims for loss of oil and natural gas production and damage to formations can occur in the well services industry.
Additionally, our business involves, and is subject to hazards associated with, the transportation of heavy equipment and materials, as well as heavily regulated explosive and radioactive materials. Regularly having a significant number of both commercial and non-commercial motor vehicles on the road creates a high risk of vehicle accidents. The occurrence of a serious accident involving our employees, equipment and/or services, could result in our being named as a defendant to a lawsuit asserting significant claims, and we may also be liable to indemnify certain third-parties, specifically including its customers, for large claims for damages in situations where our employees, equipment and/or services were involved.
Despite our efforts to maintain high safety standards, we from time to time have experienced accidents in the past, and we anticipate that we could experience accidents in the future. In addition to the property and personal losses from these accidents, the frequency and severity of these incidents affect our operating costs and insurability, as well as our relationships with customers, employees and regulatory agencies. Any significant increase in the frequency or severity of these incidents, could adversely affect the cost of, or our ability to obtain, workers’ compensation and other forms of insurance, and could have other adverse effects on our financial condition and results of operations.
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We carry a variety of insurance coverages for our operations, and we are partially self-insured for certain claims, in amounts that we believe to be customary and reasonable. However, our insurance may not be sufficient to cover any particular loss or may not cover all losses. Historically, insurance rates have been subject to various market fluctuations that may result in less coverage, increased premium costs, or higher deductibles or self-insured retentions.
Availability of filings
Our Annual reports on Form 10-K, 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 Securities Exchange Act of 1934, as amended (the “Exchange Act”), are made available free of charge on our internet web site at www.nextierofs.com, as soon as reasonably practicable after we have electronically filed the material with, or furnished it to, the Securities and Exchange Commission (the “SEC”). The SEC maintains an internet site that contains our reports, proxy and information statements and our other SEC filings. The address of that web site is https://www.sec.gov/.
We webcast our earnings calls and certain events we participate in or host with members of the investment community on our investor relations website at https://investors.nextierofs.com/ir-home. Additionally, we provide notifications of news or announcements regarding our financial performance, including SEC filings, investor events, press and earnings releases and blogs as part of our investor relations website. We have used, and intend to continue to use, our investor relations website as means of disclosing material information and for complying with our disclosure obligations under Regulation Fair Disclosure. Further corporate governance information, including our certificate of incorporation, bylaws, governance guidelines, board committee charters and code of business conduct and ethics, is also available on our investor relations website under the heading “Corporate Governance.” The contents of our websites are not intended to be incorporated by reference into this Annual Report on Form 10-K or in any other report or document we file with the SEC, and any references to our websites are intended to be inactive textual references only.
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Item 1A. Risk Factors
RISK FACTORS
An investment in our securities involves a variety of risks. In addition to the other information included or incorporated by reference in this annual report, the following risk factors should be carefully considered, as they could have a significant adverse impact on our business, financial condition and results of operations. These risks could cause our future results to differ materially from historical results and from guidance we may provide regarding our expectations of future financial performance. These risk factors do not identify all risks that we face; our operations could also be affected by factors, events, or uncertainties that are not presently known to us or that we currently do not consider to present material risks to our operations. In addition, the global economic and political climate amplifies many of these risks. All forward-looking statements made by us or on our behalf are qualified by the risks described below.
Summary of Risk Factors
A summary of significant risks that could materially adversely impact our business, financial condition or results of operations include:
Risks Related to Our Industry:
•Continuing COVID-19 impacts;
•Cyclical/seasonal business and dependence upon spending of our customers (which is volatile);
•Instability of crude oil and natural gas commodity prices;
•Adverse weather conditions impact demand services and influence costs;
•Competition and availability of equipment within the oilfield services industry affects use and price of services;
•The energy services industry’s inherent hazards;
•Competition among oilfield service and equipment providers, including impact of each provider’s reputation for environmental impact, safety and quality;
•Oilfield anti-indemnity provisions in many states that restrict or prohibit risk mitigation strategies, such as indemnification;
•New technologies developed by third parties impacting competitiveness;
•Laws and regulations regarding health, safety and protection of the environment increasing costs of doing business, penalties, damages or costs of remediation or implicate corrective measures;
•Legislative and regulatory initiatives prohibiting or impairing hydraulic fracturing operations;
•Laws and regulations addressing greenhouse gases and climate change; and
•Changes in transportation regulations increasing costs or administrative burdens.
Risks Related to Our Business
•Loss of customers;
•Detrimental performance by, or credit risk of, our customers;
•High capital costs of maintenance, upgrades, refurbishment and replacement of assets;
•Ability to employ a sufficient number of key employees, technical personnel and qualified workers;
•Overcommitments to certain supply agreement;
•Delays in deliveries, increases in costs or unavailability of key materials for our operations;
•Litigation and other proceedings, including claims for personal injury and property damage;
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•Challenges obtaining or renewing permits or authorizations for our or our customers’ operations;
•Successful identification and consummation of beneficial acquisitions;
•Time-consuming and costly integration of any acquisitions;
•Increased labor costs or failure to attract and retain qualified employees;
•Failure of our information technology systems;
•Cyber security risks;
•Failure of internal controls; and
•Violations of the U.S. Foreign Corrupt Practices Act and similar foreign anti-bribery laws.
Risks Related to Our Indebtedness
•Our substantial level of indebtedness;
•Ability to incur additional debt, despite our current indebtedness levels;
•Restrictive covenants in our agreements governing our indebtedness;
•Our variable rate debt that is subject to interest rate fluctuations;
•Restriction on our ability to raise capital on favorable terms, or at all; and
•Potential reduction or expiration of our ability to use net operating loss carryforwards to offset future taxable income for U.S. federal income tax purposes.
Risks Related to Our Common Stock
•The price of our common stock may be volatile or may decline regardless of our operating performance;
•Our shareholders may not be able to resell their shares at or above the public offering price;
•The market price of our common stock could decline and our stockholders may be diluted if large blocks of stock become available in the market;
•We do not currently pay dividends;
•We have no requirement to execute on any capital return program;
•Stockholders may be diluted by the future issuance of additional common stock;
•Keane Investor and Cerberus own a significant amount of our common stock and continue to have influence over us;
•Stockholder actions and/or acquisition of the Company is impacted by restrictive provisions in our charter documents, certain agreements governing our indebtedness, our Stockholders’ Agreement (as defined herein) and Delaware law; and
•The Court of Chancery of the State of Delaware is the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders under our formation documents.
Discussion of Risk Factors
Risks Related to Our Industry
The ongoing COVID-19 pandemic significantly reduced demand for our services and adversely impacted our financial condition, results of operations and cash flows.
The COVID-19 pandemic is ongoing, and it is uncertain when its impact on the world will wane. The effects of the COVID-19 pandemic, including actions taken by businesses and governments, resulted in a significant and swift reduction in U.S. and international economic activity beginning in the first quarter of 2020. These effects adversely affected the demand for oil and natural gas, which resulted in a reduction in demand for our services.
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The pandemic is continuously evolving, and the extent to which our operating and financial results will continue to be affected will depend on various factors beyond our control, such as the ultimate duration, severity and sustained geographic resurgence of the virus; the emergence of new variants and strains of the virus (including Delta and Omicron); and the success of actions to contain the spread of the virus and its variants, or treat its impact, such as the availability and acceptance of vaccines and treatments.
We are closely monitoring the effects of the pandemic on commodity demands, our customers, our suppliers, and on our operations and employees. These effects have included, and may continue to include, adverse revenue effects; supply chain disruptions; inflationary impacts on cost of goods and services sold, customer shutdowns of oil and gas exploration and production; employee impacts from illness, school closures and other community response measures; and temporary closures of our facilities or the facilities of our customers and suppliers.
The COVID-19 pandemic, and the volatile regional and global economic conditions stemming from it, could also exacerbate other risk factors that we identify in this Annual Report on Form 10-K. We may also continue to see an increase in the volume of litigation, including contract claims (some of which may result from force majeure claims) and employment related claims.
The COVID-19 pandemic could also have a material adverse effect on our business, results of operations and financial condition in a manner that is not currently known to us or that we do not currently believe presents significant risks to our operations.
Our business is cyclical and depends on spending and well completions by the onshore oil and natural gas industry predominately in the United States, and the level of such activity is volatile. Our business has been, and may continue to be, adversely affected by industry and financial market conditions that are beyond our control.
Our business is cyclical, and we depend on the willingness of our customers to make expenditures to explore for, develop and produce oil and natural gas from predominantly U.S. onshore unconventional resources. The willingness of our customers to undertake these activities depends largely upon prevailing industry and financial market conditions that are influenced by numerous factors over which we have no control, including:
•the impacts of the COVID-19 pandemic;
•prices and expectations about future prices for oil and natural gas;
•domestic and foreign supply of, and demand for, oil and natural gas and related products;
•the level of global and domestic oil and natural gas inventories;
•the supply of and demand for hydraulic fracturing and other oilfield services and equipment in the U.S. and the areas in which we operate;
•the cost of exploring for, developing, producing and delivering oil and natural gas;
•the availability of adequate pipeline, storage and other transportation capacity;
•lead times associated with acquiring equipment and products and availability of qualified personnel;
•the rates at which new oil and natural gas reserves are discovered;
•federal, state and local regulation of hydraulic fracturing and other oilfield service activities, such as water disposal, as well as exploration and production activities, including public pressure on governmental bodies and regulatory agencies to regulate our industry;
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•the availability of water resources, suitable proppant and chemicals in sufficient quantities for use in hydraulic fracturing fluids;
•geopolitical developments, political instability and recent (and potential future) armed hostilities in oil and natural gas producing countries;
•actions of the Organization of the Petroleum Exporting Countries, its members and other state-controlled oil companies (“OPEC+”) relating to oil price and production controls;
•advances in exploration, development and production technologies or in technologies affecting energy consumption;
•the price and availability of alternative fuels and energy sources;
•disruptions due to natural disasters, unexpected or extreme weather conditions, public health crises (such as coronavirus) and similar factors;
•merger and divestiture activity amongst oil and natural gas producers;
•uncertainty in capital and commodities markets and the ability of oil and natural gas producers and oil and natural gas midstream operators to raise equity capital and debt financing;
•investor and public sentiment related to corporate social responsibility and sustainability; and
•U.S. federal, state and local and non-U.S. governmental regulations and taxes.
As we have experienced since late March of 2020, the volatility of the oil and natural gas industry and the resulting impact on exploration and production activity could adversely impact the level of drilling and completion activity by some of our customers. This volatility may result in a decline in the demand for our services or adversely affect the price of our services. In addition, material declines in oil and natural gas prices, or drilling or completion activity in the U.S. oil and natural gas shale regions, could have a material adverse effect on our business, financial condition, prospects, results of operations and cash flows. Furthermore, a decrease in the development of oil and natural gas reserves in the U.S. may also have an adverse impact on our business, even in an environment of strong oil and natural gas prices.
A decline in or substantial volatility of crude oil and natural gas commodity prices could adversely affect the demand for our services.
The demand for our services is substantially influenced by current and anticipated crude oil and natural gas commodity prices, the related level of drilling and completion activity and general production spending in the areas in which we have operations. Volatility or weakness in crude oil and natural gas commodity prices (or the perception that crude oil and natural gas commodity prices will decrease) affects the operational and capital spending patterns of our customers, and the products and services we provide are, to a substantial extent, deferrable in the event oil and natural gas companies reduce capital expenditures. During periods of declining oil and natural gas prices or when pricing remains depressed, such as during the COVID-19 pandemic, our customer base may experience significant declines in drilling, completion and production activities, which in turn may result in reduced utilization and increased competition and pricing pressure to varying degrees across our service lines and operating areas.
Historically, prices for crude oil and natural gas have been extremely volatile, and these prices are expected to experience continued volatility. For example, since 2016, crude oil prices have ranged from a low of ($36.98) in 2020 to a high of $85.64 per barrel in 2021. During 2021, NYMEX crude oil prices ranged from approximately $47.47 to $85.64 per barrel, with natural gas prices ranging from $2.43 per million British thermal units (“MMbtu”) to $23.86 per MMbtu. Continued price volatility for oil and natural gas is expected during 2022.
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Worldwide military, political and economic events, including initiatives by OPEC+, affect both the demand for, and the supply of, oil and natural gas. Weather conditions, governmental regulation (both in the United States and elsewhere), levels of consumer demand, commercial development of economically viable alternative energy sources (such as wind, solar, geothermal, tidal, fuel cells and biofuels), fuel conservation measures, the availability of pipeline capacity and other factors that will be beyond our control may also affect the supply of, demand for, and price of oil and natural gas. This, in turn, could result in lower demand for our services and cause lower pricing and utilization levels for our services.
Adverse weather conditions could impact demand for our services or materially impact our costs.
Our business could be materially adversely affected by adverse weather conditions. Our operations and the operations of our customers may be adversely affected by seasonal weather conditions, severe weather events and natural disasters. For example, periods of drought, hurricanes, tropical storms, heavy snow, ice or rain may result in customer delays and other disruptions to our services, including availability of key products such as sand and water. Repercussions of adverse weather conditions may include:
•curtailment of services;
•weather-related damage to facilities and equipment, resulting in delays in operations;
•inability to deliver equipment, personnel and products to job sites in accordance with contract schedules;
•increase in the price of key products or insurance; and
•loss of productivity.
Competition and availability of excess equipment within the oilfield services industry may adversely affect our ability to market and price our services.
The oilfield services industry is highly competitive. The principal competitive tactics in our markets are generally price, technical expertise, the availability and condition of equipment, work force capability, safety record, reputation and experience. Furthermore, as a result of this competition, available equipment in the markets in which one or more of our product lines competes at times may exceed the demand for such equipment. This excess supply of equipment may result from many factors, including without limitation, a low commodity price environment, increase in the construction of new equipment, or reactivation and improvement of existing equipment. Excess capacity may result in substantial competition for a diminishing amount of demand and/or significant price competition, which could have a material adverse effect on our results of operations, financial condition and prospects.
The oilfield services industry is highly fragmented and includes several large companies that compete in many of the markets we serve, as well as numerous small companies that compete with us on a local basis. Some of our competitors may have greater resources and/or name recognition, which could allow them to better withstand industry downturns and to compete more effectively on the basis of technology, geographic scope, retained skilled personnel and economies of scale. In addition, our industry has experienced recent consolidation through mergers and acquisitions, which could lead to increased resources and capabilities for our competitors. There may also be new companies that enter our business, or re-enter our business with significantly reduced indebtedness following emergence from bankruptcy, or our existing and potential future customers may develop their own oilfield solutions. Our operations may be adversely affected if our current competitors or new market entrants introduce new products, technology or services with better features, performance, prices or other characteristics than our products and services or expand in service areas where we operate.
We periodically seek to increase prices of our services to offset rising costs and to generate higher returns for our stockholders. Because we operate in a very competitive industry, however, we are not always successful in raising or maintaining our existing prices. Even if we are able to increase our prices, we may not be able to do so at a
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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 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 dedicated contracts that were 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 excess equipment in the market can cause us 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 excess equipment in the oil and natural gas service businesses or the level of demand for our services.
Our operations are subject to hazards inherent in the energy services industry.
Risks inherent to our industry can cause personal injury, loss of life, suspension of or impact upon operations, damage to geological formations, damage to facilities, business interruption and damage to, or destruction of, property, equipment and the environment. Such risks may include, but are not limited to:
•equipment defects;
•vehicle accidents;
•fires, explosions or uncontrollable flows of gas or well fluids;
•unusual or unexpected geological formations or pressures and industrial accidents;
•blowouts;
•cratering;
•loss of well control;
•collapse of the borehole; and
•damaged or lost drilling and well completions equipment.
Catastrophic or significantly adverse events can occur at well sites where we conduct our operations, including explosions, fires, personal injuries, property damage, pollution, clean-up responsibility and regulatory responsibility. In response, we typically seek indemnities, releases and limitations on liability in our contracts with our customers, together with liability insurance coverage, to protect us from potential liability related to such occurrences. However, it is possible that customers or insurers could seek to avoid such provisions (or compliance with such provisions) or be financially unable to meet their obligations, or a court may decline to enforce such provisions. Damages that are not indemnified or released could greatly exceed available insurance coverage and could have a material adverse effect on our business, financial condition, prospects and results of operations.
Catastrophic or significantly adverse events can also occur at our facilities and during transport of our equipment, commodities, and personnel to well sites. Our safety procedures may not always prevent such damages. Our insurance coverage or coverage of applicable vendors and service providers may be inadequate to cover our liabilities. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable and commercially justifiable or on terms as favorable as our current arrangements. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations, and cash flows.
In addition, our services could become a source of spills or releases of fluids, including chemicals used during activities, at the site where such services are performed, or could result in the discharge of such fluids into underground formations that were not targeted for fracturing or activities, such as potable aquifers. These risks could
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expose us to substantial liability for personal injury, wrongful death, property damage, loss of oil and natural gas production, pollution and other environmental damages and could result in a variety of claims, losses and remedial obligations that could have an adverse effect on our business and results of operations. The existence, frequency and severity of such incidents could affect operating costs, insurability, reputation and relationships with customers, employees and regulators. Any litigation or claims, even if fully indemnified or insured, could negatively affect our reputation with our customers and the public and make it more difficult for us to compete effectively or obtain adequate insurance in the future.
Competition among oilfield service and equipment providers is affected by each provider’s reputation for environmental impact, safety and quality.
Our activities are subject to a wide range of national, state and local environmental, occupational health and safety laws and regulations. In addition, customers maintain their own compliance and reporting requirements. Failure to comply with these environmental, health and safety laws and regulations, or failure to comply with our customers’ compliance or reporting requirements, could tarnish our reputation for safety and quality and have a material adverse effect on our competitive position. In particular, our customers may elect not to purchase our services if they view our environmental or safety record as unsatisfactory, which could cause us to lose customers and substantial revenue.
Oilfield anti-indemnity provisions enacted by many states may restrict or prohibit a party’s indemnification of us.
We typically enter into agreements with our customers governing the provision of our services, which usually include certain indemnification provisions for losses resulting from operations. Such agreements may require each party to indemnify the other against certain claims regardless of the negligence or other fault of the indemnified party; however, many states place limitations on contractual indemnity agreements, particularly agreements that indemnify a party against the consequences of its own negligence. Furthermore, 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, whether enacted/amended in the future or currently in existence, may restrict or void a party’s indemnification of us, which could have a material adverse effect on our business, financial condition, prospects and results of operations.
New technology may cause us to become less competitive.
The oilfield services industry is subject to the introduction of new drilling and completion techniques and services using new technologies, some of which may be subject to patent or other intellectual property protections. As competitors and others use or develop new or comparable technologies in the future, we may lose market share or be placed at a competitive disadvantage. In addition, technological changes, process improvements and other factors that increase operational efficiencies could continue to result in oil and natural gas wells being completed more quickly, which could reduce the number of revenue earning days. Furthermore, we may face competitive pressure to develop, implement or acquire certain new technologies at a substantial cost. Some of our competitors have greater financial, technical and personnel resources that may allow them to enjoy technological advantages and develop and implement new products on a timely basis or at an acceptable cost. We cannot be certain that we will be able to develop and implement new technologies or products on a timely basis or at an acceptable cost. Limits on our ability to develop, acquire, effectively use and implement new and emerging technologies may have a material adverse effect on our business, financial condition, prospects or results of operations. Further, some of our competitors and suppliers have a substantial amount of intellectual property related to new technologies. We cannot guarantee that our processes and products do not and will not infringe issued patents (whether present or future) or other intellectual property rights belonging to others, including, without limitation, situations in which our products, processes or technologies may be covered by patent applications filed by other parties in the U.S. or abroad.
Existing or future laws and regulations and indirect consequences related to greenhouse gases and climate change could have a negative impact on our business and may result in additional compliance obligations with respect to the release, capture and use of carbon dioxide that could have a material adverse effect on our business, results of operations, prospects and financial condition.
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Changes in environmental requirements related to greenhouse gases and climate change may negatively impact demand for our services. For example, oil and natural gas exploration and production may decline as a result of environmental requirements, including land use policies responsive to environmental concerns. Federal, state and local agencies have been evaluating climate-related legislation and other regulatory initiatives that would restrict emissions of greenhouse gases in areas in which we conduct business. Because our business depends on the level of activity in the oil and natural gas industry, existing or future laws and regulations related to emissions of greenhouse gases 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 reduce demand for oil and natural gas. Likewise, such restrictions may result in additional compliance obligations with respect to the release, capture, sequestration and use of carbon dioxide that could have a material adverse effect on our business, results of operations, prospects and financial condition.
Additionally, increasing political and social attention to global climate change has resulted in pressure upon stockholders, financial institutions and/or financial markets to modify their relationships with oil and gas companies and to limit investments and/or funding to such companies, which could increase our costs or otherwise adversely affect our business and results of operations.
We are subject to federal, state and local laws and regulations regarding issues of health, safety and protection of the environment. Under these laws and regulations, we may become liable for penalties, damages or costs of remediation or other corrective measures. Any changes in laws or government regulations could increase our costs of doing business.
Our operations are subject to stringent federal, state, local and tribal laws and regulations relating to, among other things, protection of natural resources, clean air and drinking water, wetlands, endangered species, greenhouse gasses, areas that are not in attainment with air quality standards, the environment, health and safety, chemical use and storage, waste management, waste disposal and transportation of waste and other hazardous and nonhazardous materials. Our operations involve risks of environmental liability, including leakage from an operator’s casing during our operations or accidental spills onto or into surface or subsurface soils, surface water or groundwater. Some environmental laws and regulations may impose strict liability, joint and several liability or both. In some situations, we could be exposed to liability as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, third parties without regard to whether we caused or contributed to the conditions. Additionally, environmental concerns, including potential emissions affecting clean air, including methane, drinking water contamination and seismic activity, have prompted investigations that could lead to the enactment of regulations, limitations, restrictions or moratoria that could potentially have a material adverse impact on our business. Actions arising under these laws and regulations could result in the shutdown of our operations, fines and penalties (administrative, civil or criminal), revocations of or restrictions in permits to conduct business, expenditures for remediation or other corrective measures and/or claims for liability for property damage, exposure to hazardous materials, exposure to hazardous waste, nuisance or personal injuries. Sanctions for noncompliance with applicable environmental laws and regulations may also include the assessment of administrative, civil or criminal penalties, revocation of or restrictions in permits and temporary or permanent cessation of operations in a particular location and issuance of corrective action orders. Such claims or sanctions and related costs could cause us to incur substantial costs or losses and could have a material adverse effect on our business, financial condition, prospects and results of operations. Additionally, an increase in regulatory requirements, limitations, restrictions or moratoria on oil and natural gas exploration and completion activities at a federal, state or local level could significantly delay or interrupt our operations, limit the amount of work we can perform, increase our costs of compliance, or increase the cost of our services; thereby possibly having a material adverse impact on our financial condition. Given the recent administration change in the United States, we expect that the regulations around the oil and gas industry may increase and/or become stricter, which may further any potential material adverse impact on our financial condition. For example, the EPA’s recently proposed changes to the standards of performance and emissions guidelines for new, reconstructed, and modified sources in the oil and natural gas sector could require additional monitoring, upgraded control equipment, and/or modified operations at current oil and natural gas operations.
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If we do not perform in accordance with government, industry, customer or our own health, safety and environmental standards (including standards put in place related to the COVID-19 pandemic), we could lose business from our customers, many of whom have an increased focus on environmental, health and safety issues.
We are subject to requirements imposed by the EPA, U.S. Department of Transportation, U.S. Nuclear Regulatory Commission, OSHA and state regulatory agencies that regulate operations to prevent air, soil and water pollution, and protect worker health and safety.
The EPA regulates air emissions from all engines, including off-road diesel engines that are used by us to power equipment in the field. Under these U.S. emission control regulations, we could be limited in the number of certain off-road diesel engines we can purchase. Further, the requirement to comply with emission control and fuel quality regulations could result in increased costs.
In addition, as part of our business, we handle, transport, and dispose of a variety of fluids and substances used by our customers in connection with their oil and natural gas exploration and production activities. We also generate and dispose of nonhazardous and hazardous wastes. The generation, handling, transportation, and disposal of these fluids, substances, and wastes are regulated by a number of laws, including CERCLA, RCRA, the Clean Water Act, the SDWA and analogous state laws. Under RCRA, the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes are regulated. RCRA currently exempts many oil and gas exploration and production wastes from classification as hazardous waste. However, these oil and gas exploration and production wastes may still be regulated under state solid waste laws and regulations, and it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous waste in the future.
Failure to properly handle, transport or dispose of these materials or otherwise conduct our operations in accordance with these and other environmental laws could expose us to liability for governmental penalties, third-party claims, cleanup costs associated with releases of such materials, damages to natural resources, and other damages, as well as potentially impair our ability to conduct our operations. Moreover, certain of these environmental laws impose joint and several, strict liability even though our conduct in performing such activities was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third-parties was the basis for such liability. In addition, environmental laws and regulations are subject to frequent change and if existing laws, regulatory requirements or enforcement policies were to change in the future, we may be required to make significant unanticipated capital and operating expenditures.
Laws and regulations protecting the environment generally have become more stringent over time, and we expect them to continue to do so. This could lead to material increases in our costs, and liability exposure, for future environmental compliance and remediation.
Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing could prohibit, restrict or limit hydraulic fracturing operations, could increase our operating costs or could result in the disclosure of proprietary information resulting in competitive harm.
During recent sessions of the U.S. Congress, several pieces of legislation were introduced in the U.S. Senate and House of Representatives for the purpose of amending environmental laws such as the Clean Air Act, the SDWA and the Toxic Substances Control Act with respect to activities associated with extraction and energy production industries, especially the oil and gas industry. Furthermore, various items of legislation and rulemaking have been proposed that would regulate or prevent federal regulation of hydraulic fracturing on federally owned land. Proposed rulemaking from the EPA and OSHA could increase our regulatory requirements, which could increase our costs of compliance or increase the costs of our services, thereby possibly having a material adverse impact on our business and results of operations.
If the EPA, DOI, or another federal or state agency asserts jurisdiction over certain aspects of hydraulic fracturing operations, an additional level of regulation established at the federal or state level could lead to operational delays and increase our costs. In December 2016, the EPA issued a study of the potential impacts of
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hydraulic fracturing on drinking water and groundwater. The EPA report states that there is scientific evidence that hydraulic fracturing activities can impact drinking resources under some circumstances, and identifies certain conditions in which the EPA believes the impact of such activities on drinking water and groundwater can be more frequent or severe. The EPA study could spur further initiatives to regulate hydraulic fracturing under the SDWA or otherwise. Many regulatory and legislative bodies routinely evaluate the adequacy and effectiveness of laws and regulations affecting the oil and gas industry. As a result, state legislatures, state regulatory agencies and local municipalities may consider legislation, regulations or ordinances, respectively, that could affect all aspects of the oil and natural gas industry and occasionally take action to restrict or further regulate hydraulic fracturing operations. At this time, it is not possible to estimate the potential impact on our business of these state and municipal actions or the enactment of additional federal or state legislation or regulations affecting hydraulic fracturing. Compliance, stricter regulations or the consequences of any failure to comply by us could have a material adverse effect on our business, financial condition, prospects and results of operations.
Many states in which we operate require the disclosure of some or all of the chemicals used in our hydraulic fracturing operations. Certain aspects of one or more of these chemicals may be considered proprietary by us or our chemical suppliers. Disclosure of our proprietary chemical information to third parties or to the public, even if inadvertent, could diminish the value of our trade secrets or those of our chemical suppliers and could result in competitive harm to us, which could have an adverse impact on our business, financial condition, prospects and results of operations.
We are also aware that some states, counties and municipalities have enacted or are considering moratoria on hydraulic fracturing. For example, New York and Vermont, states in which we have no operations, have banned or are in the process of banning the use of high-volume hydraulic fracturing. Alternatively, some municipalities are considering or have considered zoning and other ordinances, the conditions of which could impose a de facto ban on drilling and/or hydraulic fracturing operations. Further, some states, counties and municipalities are closely examining water use issues, such as permit and disposal options for processed water, which could have a material adverse impact on our financial condition, prospects and results of operations, if such additional permitting requirements are imposed upon our industry. Additionally, our business could be affected by a moratorium or increased regulation of companies in our supply chain, such as sand mining by our proppant suppliers, which could limit our access to supplies and increase the costs of our raw materials. At this time, it is not possible to estimate how these various restrictions could affect our ongoing operations.
Changes in transportation regulations may increase our costs and negatively impact our results of operations.
We are subject to various transportation regulations, including regulation of motor carriers by the U.S. Department of Transportation and by various federal, state and tribal agencies, whose regulations include certain permit requirements imposed by highway and safety authorities. These regulatory authorities exercise broad powers over our trucking operations, generally governing such matters as the authorization to engage in motor carrier operations, safety, equipment testing, driver requirements and specifications and insurance requirements. The trucking industry is subject to possible regulatory and legislative changes that may impact our operations, such as changes in fuel emissions limits, hours of service regulations that govern the amount of time a driver may drive or work in any specific period and limits on vehicle weight and size. As the federal government continues to develop and propose regulations relating to fuel quality, engine efficiency and greenhouse gas emissions, we may experience an increase in costs related to truck purchases and maintenance, impairment of equipment productivity, a decrease in the residual value of vehicles, unpredictable fluctuations in fuel prices and an increase in operating expenses. Increased truck traffic may contribute to deteriorating road conditions in some areas where our operations are performed. Our operations, including routing and weight restrictions, could be affected by road construction, road repairs, detours and state and local regulations and ordinances restricting access to certain roads. Proposals to increase federal, state or local taxes, including taxes on motor fuels, are also made from time to time, and any such increase would increase our operating costs. Also, state and local regulation of permitted routes and times on specific roadways could adversely affect our operations. We cannot predict whether, or in what form, any legislative or regulatory changes or municipal ordinances applicable to our logistics operations will be enacted and to what
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extent any such legislation or regulations could increase our costs or otherwise adversely affect our business or operations.
Risks Related to Our Business
The loss of one or more significant customers could adversely affect our financial condition, prospects and results of operations.
Our business, financial condition, prospects and results of operations could be materially adversely affected, if one or more of our significant customers ceases to engage us for our services on favorable terms or at all, or fails to pay or delays in paying us significant amounts of our outstanding receivables. Our completions business has historically had contracts with a limited number of our customers that are annual to multi-year.
Disruption caused by continued business and governmental responses to the COVID-19 pandemic has created increased vulnerability to loss of customers or loss of long-term contracts as demand for oilfield services has decreased and competition for the available jobs has increased. We may be unable to replace dedicated contracts that were 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.
Additionally, the E&P industry is characterized by frequent consolidation activity. Changes in ownership of our customers may result in the loss of, or reduction in, business from those customers, which could materially and adversely affect our business, financial condition, prospects or results of operations.
We are exposed to the credit risk of our customers, and any material nonpayment or nonperformance by our customers could adversely affect our financial results.
We are subject to the risk of loss resulting from nonpayment or nonperformance by our customers, many of whose operations are concentrated solely in the domestic E&P industry which, as described above, is subject to volatility and, therefore, credit risk. Our credit procedures and policies may not be adequate to fully reduce customer credit risk. If we are unable to adequately assess the creditworthiness of existing or future customers or unanticipated deterioration in their creditworthiness, any resulting increase in nonpayment or nonperformance by them and our inability to re-market or otherwise use our equipment could have a material adverse effect on our business, financial condition, prospects and results of operations.
Our assets require significant amounts of capital for maintenance, upgrades and refurbishment and may require significant capital expenditures for new equipment.
Our hydraulic fracturing fleets and other service-related equipment require significant capital investment in maintenance, upgrades and refurbishment to maintain their competitiveness. Our fleets and other equipment typically do not generate revenue while they are undergoing maintenance, refurbishment or upgrades. Any maintenance, upgrade or refurbishment project for our assets could increase our indebtedness or reduce cash available for other opportunities. Furthermore, such projects may require proportionally greater capital investments as a percentage of total asset value, which may make such projects difficult to finance on acceptable terms. To the extent we are unable to fund such projects, we may have less equipment available for service, or our equipment may not be attractive to potential or current customers. Additionally, increased demand, competition, environmental and safety requirements or advances in technology within our industry may require us to update or replace existing fleets or build or acquire new fleets. Such demands on our capital or reductions in demand for our hydraulic fracturing fleets and other service-related equipment and the increase in cost to maintain labor necessary for such maintenance and improvement, in each case, could have a material adverse effect on our business, liquidity position, financial condition, prospects and results of operations.
We may be unable to employ a sufficient number of key employees, technical personnel and other skilled or qualified workers.
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The delivery of our services and products requires personnel with specialized skills and experience who can perform physically demanding work. As a result of the volatility in the energy service industry and the demanding nature of the work, workers may choose to pursue employment with our competitors or in fields that offer a less demanding work environment. In addition, since the onset of the COVID-19 pandemic, we may not have sufficient employees who are able to work at job sites, due to illness, school closures and other community response measures; and temporary closures of our facilities or the facilities of our customers and suppliers, or health and safety protocols.
Furthermore, we require full compliance with the Immigration Reform and Control Act of 1986 and other laws concerning immigration and the hiring of legally documented workers. We recognize that foreign nationals may be a valuable source of talent, but that not all foreign nationals are authorized to work for U.S. companies immediately, without first obtaining a required work authorization from the U.S. Department of Homeland Security or similar government agency. Our ability to be productive and profitable will depend upon our ability to employ and retain skilled workers. In addition, our ability to adjust our operations according to geographic demand for our services depends in part on our ability to relocate or increase the size of our skilled labor force. The demand for skilled workers in our areas of operations can be high, the supply may be limited, and we may be unable to relocate our employees from areas of lower utilization to areas of higher demand. A significant increase in the wages paid by competing employers could result in a reduction of our skilled labor force, increases in the wage rates that we must pay, or both. Furthermore, a significant decrease in the wages paid by us or our competitors as a result of reduced industry demand could result in a reduction of the available skilled labor force, and there is no assurance that the availability of skilled labor will improve following a subsequent increase in demand for our services or an increase in wage rates. If any of these events were to occur, our capacity and profitability could be diminished and our growth potential could be impaired.
We depend heavily on the efforts of executive officers, managers and other key employees to manage our operations. The unexpected loss or unavailability of key members of management or technical personnel (including due to illness related to COVID-19) may have a material adverse effect on our business, financial condition, prospects or results of operations.
Our commitments under supply agreements could exceed our requirements, exposing us to risks including price, timing of delivery and quality of products and services upon which our business relies.
We have purchase commitments with certain vendors to supply a majority of the proppant that we may provide in our operations. Some of these agreements are take-or-pay agreements with minimum purchase obligations. If demand for our hydraulic fracturing services decreases, our need for the raw materials and products we supply as part of these services also decreases. If demand decreases enough, we could have contractual minimum commitments that exceed the required amount of goods we need to supply to our customers. In this instance, we could be required to purchase goods that we do not have a present need for, pay for goods that we do not take delivery of or pay prices in excess of market prices at the time of purchase. We may not be able to reduce, extend, eliminate or otherwise address near-term obligations to our satisfaction, which could result in an adverse effect on our financial condition.
Delays in deliveries of key raw materials or increases in the cost of key raw materials could harm our business, results of operations and financial condition.
We have established relationships with a limited number of suppliers of our raw materials (such as proppant, chemicals, cement, steel, or coiled tubing) and finished products (such as fluid-handling equipment). Raw materials essential to our business are normally readily available. However, high levels of demand for raw materials, such as proppant and hydrochloric acid, as well as oil and natural gas based derivatives, have triggered constraints in the supply chain of those raw materials and could dramatically increase the prices of such raw materials. Should any of our current suppliers be unable to provide the necessary raw materials or finished products or otherwise fail to deliver the products in a timely manner and in the quantities required, any resulting delays in the provision of services could have a material adverse effect on our business, financial condition, results of operations and cash flows. Additionally, increasing costs of certain raw materials, including proppant, may negatively impact demand
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for our services or the profitability of our business operations. In the past, our industry faced sporadic shortages associated with hydraulic fracturing operations, such as proppant and other raw materials, requiring work stoppages, which adversely impacted the operating results of several competitors. We may not be able to mitigate any future shortages of raw materials, including proppants.
We may be subject to litigation and other proceedings, including claims for personal injury and property damage, which could materially adversely affect our financial condition, prospects and results of operations.
Our services are subject to inherent risks that can cause personal injury or loss of life, damage to or destruction of property, equipment or the environment or the suspension of our operations. Our operations are subject to, and exposed to, employee/employer liabilities and risks such as wrongful termination, discrimination, labor organizing, retaliation claims and general human resource related matters. Litigation arising from operations where our facilities are located, or our services are provided, may cause us to be named as a defendant in lawsuits asserting potentially large claims including claims for exemplary damages. Additionally, because our business is related to fossil fuel production, there is an increasing risk that we may be subject to generalized lawsuits which attempt to hold companies in the fossil fuel industry liable for alleged local impacts of climate change. Such legal theories are still developing, making it difficult to assess the likelihood or scope of potential liabilities. We maintain what we believe is customary and reasonable insurance to protect our business against these potential losses, but such insurance may not be adequate to cover our liabilities, and we are not fully insured against all risks, including losses related to alleged climate claim damages. Further, our insurance has deductibles or self-insured retentions and contains certain coverage exclusions. The current trend in the insurance industry is towards larger deductibles and self-insured retentions. In addition, insurance may not be available in the future at rates that we consider reasonable and commercially justifiable, compelling us to have larger deductibles or self-insured retentions to effectively manage expenses. As a result, we could become subject to material uninsured liabilities or situations where we have high deductibles or self-insured retentions that expose us to liabilities that could have a material adverse effect on our business, financial condition, prospects or results of operations.
Litigation and other proceedings could have a negative impact on our business.
The nature of our business makes us susceptible to legal proceedings and governmental audits and 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 that could have a material adverse effect on our business, financial condition and results of operations. Similarly, any legal proceedings or claims, even if fully indemnified or insured, could negatively impact 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. See Note (18) Commitments and Contingencies of Part II, “Item 8. Financial Statements and Supplementary Data” for further discussion of our legal and environmental contingencies for the years ended December 31, 2021, 2020 and 2019.
Delays in obtaining, or inability to obtain or renew, permits or authorizations by our customers for their operations or by us for our operations could impair our business.
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In most states, our customers are required to obtain permits or authorizations from one or more governmental agencies or other third parties to perform drilling and completion activities, including hydraulic fracturing. Such permits or approvals are typically required by state agencies, but can also be required by federal and local governmental agencies or other third parties. The requirements for such permits or authorizations vary depending on the location where such drilling and completion activities will be conducted. As with most permitting and authorization processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit or approval to be issued and the conditions which may be imposed in connection with the granting of the permit. In some jurisdictions, such as within the jurisdiction of the Delaware River Basin Commission, certain regulatory authorities have delayed or suspended the issuance of permits or authorizations, while the potential environmental impacts associated with issuing such permits can be studied and appropriate mitigation measures evaluated. New York and Vermont, states in which we have no operations, have prohibited hydraulic fracturing statewide. In Texas, rural water districts have begun to impose restrictions on water use and may require permits for water used in drilling and completion activities. Permitting, authorization or renewal delays, the inability to obtain new permits or the revocation of current permits could cause a loss of revenue and potentially have a materially adverse effect on our business, financial condition, prospects or results of operations.
We are also required to obtain federal, state, local and/or third-party permits and authorizations in some jurisdictions in connection with our wireline services. These permits, when required, impose certain conditions on our operations. Any changes in these requirements could have a material adverse effect on our business, financial condition, prospects and results of operations.
We may not be successful in identifying and making acquisitions.
Part of our strategy is to continue to expand our scope and customer relationships, increase our access to technology and to grow our business, which is dependent on our ability to make acquisitions that result in accretive revenues and earnings. We may be unable to make accretive acquisitions or realize expected benefits of any acquisitions for any of the following reasons:
• failure to identify attractive targets;
• incorrect assumptions regarding the future liabilities or future results of acquired operations or assets or expected cost reductions or other synergies expected to be realized as a result of acquiring operations or assets;
• failure to obtain financing on acceptable terms or at all;
• restrictions in our debt agreements;
• failure to successfully integrate the operations or management of any acquired operations or assets;
• failure to retain or attract key employees;
• new or expanded areas of operational risk (such as offshore, international operations, or power production services) and related costs and demands of any applicable regulatory compliance; and
• diversion of management’s attention from existing operations or other priorities.
Our acquisition strategy requires that we successfully integrate acquired companies into our business practices, as well as our procurement, management and enterprise-wide information technology systems. We may not be successful in implementing our business practices at acquired companies, and our acquisitions could face difficulty in transitioning from their previous information technology systems to our own. Furthermore, unexpected costs and challenges may arise whenever businesses with different operations or management are combined. Any such difficulties, or increased costs associated with such integration, could affect our business, financial performance and operations.
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If we are unable to identify, complete and integrate acquisitions, it could have a material adverse effect on our growth strategy, business, financial condition, prospects and results of operations.
Integrating acquisitions may be time-consuming and create costs that could reduce our net income and cash flows.
Part of our strategy includes pursuing acquisitions that we believe will be accretive to our business. If we consummate an acquisition, such as the Alamo Acquisition in 2021 and the C&J Merger in 2019, the process of integrating the acquired business may be complex and time consuming, may be disruptive to the business and may cause an interruption of, or a distraction of management’s attention from, the business as a result of a number of obstacles, including, but not limited to:
•a failure of our due diligence process to identify significant risks or issues;
•the loss of customers of the acquired company or our company;
•customers or suppliers may seek to modify contractual obligations with us;
•negative impact on the brands or banners of the acquired company or our company;
•a failure to maintain or improve the quality of our customer service;
•difficulties assimilating the operations and personnel of the acquired company;
•our inability to retain key personnel of the acquired company;
•the incurrence of unexpected expenses and working capital requirements;
•our inability to achieve the financial and strategic goals, including synergies, for the combined businesses;
•difficulty in maintaining internal controls, procedures and policies;
•mistaken assumptions about the overall costs of equity or debt; and
•unforeseen difficulties operating in new product areas or new geographic areas.
Any of the foregoing obstacles, or a combination of them, could decrease gross profit margins or increase selling, general and administrative expenses in absolute terms and/or as a percentage of net sales, which could in turn negatively impact our net income and cash flows.
We may not be able to consummate acquisitions in the future on terms acceptable to us, or at all. In addition, future acquisitions are accompanied by the risk that the obligations and liabilities of an acquired company may not be adequately reflected in the historical financial statements of that company and the risk that those historical financial statements may be based on assumptions which are incorrect or inconsistent with our assumptions or approach to accounting policies. Any of these material obligations, liabilities or incorrect or inconsistent assumptions could adversely impact our results of operations, prospects and financial condition.
If labor costs increase or we fail to attract and retain qualified employees our business, results of operations, cash flows and financial condition may be adversely affected.
The labor markets in the industries in which we operate are competitive. We must attract, train and retain a large number of qualified employees while controlling related labor costs. We face significant competition for these employees from the industries in which we operate as well as from other industries. Tighter labor markets may make it even more difficult for us to hire and retain qualified employees and control labor costs. Our ability to attract qualified employees and control labor costs is subject to numerous external factors, including prevailing wage rates, employee preferences, employment law and regulation, environmental, health and safety regulation, labor relations
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and immigration policy. A significant increase in competition or cost increase arising from any of the aforementioned factors in may have a material adverse impact on our business, results of operations and financial condition.
A failure of our information technology systems, including our enterprise resource planning system and our digital hub, could have a material adverse effect on our business, financial condition, results of operations and cash flows and could adversely affect the effectiveness of our internal control over financial reporting.
We rely on sophisticated information technology systems and infrastructure to support our business. Any of these systems may be susceptible to outages due to fire, floods, power loss, telecommunications failures, usage errors by employees, computer viruses, cyber-attacks or other security breaches or similar events. A failure or prolonged interruption in our information technology systems, including our digital logistics platform, or difficulties encountered in upgrading our systems or implementing new systems that compromises our ability to meet our customers’ needs or impairs our ability to record, process and report accurate information, could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss.
The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain processing activities. We use these technologies for internal purposes, including data storage (which may include personal identification information of our employees as well as our proprietary business information and that of our customers, suppliers, investors and other stakeholders), processing, and transmissions, as well as in our interactions with customers and suppliers. For example, we depend on digital technologies to perform many of our services and processes and to record operational and financial data. At the same time, cyber incidents, which could include, among other things, deliberate attacks, unintentional events, computer viruses, malicious or destructive code, ransomware, social engineering attacks (including phishing and impersonation), hacking, denial-of-service attacks and other attacks and similar disruptions from the unauthorized use of or access to computer systems, have increased. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Our technologies, systems and networks, as well as those of our customers, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary information, personal information and other data, or other disruption of our business operations. In addition, certain cyber incidents, such as unauthorized surveillance, may remain undetected for an extended period of time. Our systems and insurance coverage for protecting against cyber security risks, including cyberattacks, may not be sufficient and may not protect against or cover all of the losses we may experience as a result of the realization of such risks. In addition, these risks could harm our reputation and our relationships with customers, suppliers, employees, and other third-parties, and may result in claims against us, including liability under laws that protect the privacy of personal information. As cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate the effects of cyber incidents.
Disruption caused by business responses to the COVID-19 pandemic, including working remote arrangements, may create increased vulnerability to cybersecurity incidents, including breaches of information systems security, which could damage our reputation and commercial relationships, disrupt operations, increase costs and/or decrease revenues, and expose us to claims from customers, suppliers, financial institutions, regulators, employees and others, which, individually or in the aggregate could have a material adverse effect on our financial condition and results of operations.
If we fail to maintain an effective system of internal controls as required by Section 404 of the Sarbanes-Oxley Act of 2002, we may not be able to report our financial results accurately or prevent fraud, which could adversely affect our business and result in material misstatements in our financial statements.
Effective internal controls are necessary for us to provide timely and reliable financial reports, prevent fraud and to operate successfully as a publicly traded company. Our efforts to maintain our internal controls may not
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be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002 (“Section 404”). For example, Section 404 requires us, among other things, to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting. This assessment includes disclosure of any deficiencies or material weaknesses identified by our management in our internal control over financial reporting. Any failure to develop, implement or maintain effective internal controls or to improve our internal controls could harm our operating results, prevent us from identifying future deficiencies and material weaknesses or cause us to fail to meet our reporting obligations. Given the difficulties inherent in the design and operation of internal controls over financial reporting, we can provide no assurance as to our, or our independent registered public accounting firm’s conclusions, about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404. Ineffective internal controls could result in material misstatements in our financial statements and subject us to increased regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business.
We could be adversely affected by violations of the U.S. Foreign Corrupt Practices Act and similar foreign anti-bribery laws.
The United States Foreign Corrupt Practices Act (the “FCPA”) and similar worldwide anti-bribery laws generally prohibit companies and their intermediaries and partners from making, offering or authorizing improper payments to non-U.S. government officials for the purpose of obtaining or retaining business. Although we currently have limited international operations, we may do business in the future in countries or regions where strict compliance with anti-bribery laws may conflict with local customs and practices. Our employees, intermediaries, and partners may face, directly or indirectly, corrupt demands by government officials, political parties and officials, tribal or insurgent organizations, or private entities in the countries in which we operate or may operate in the future. As a result, we face the risk that an unauthorized payment or offer of payment could be made by one of our employees, intermediaries, or partners even if such parties are not always subject to our control or are not themselves subject to the FCPA or other anti-bribery laws to which we may be subject. We are committed to doing business in accordance with applicable anti-bribery laws and have implemented policies and procedures concerning compliance with such laws. Our existing safeguards and any future improvements, however, may prove to be less than effective, and our employees, intermediaries, and partners may engage in conduct for which we might be held responsible. Violations of the FCPA and other anti-bribery laws (either due to our acts, the acts of our intermediaries or partners, or our inadvertence) may result in criminal and civil sanctions and could subject us to other liabilities in the U.S. and elsewhere. Even allegations of such violations could disrupt our business and result in a material adverse effect on our business and operations.
Risks Related to Our Indebtedness
Our substantial level of indebtedness could adversely affect our financial condition and prevent us from fulfilling our obligations under our indebtedness.
We have a significant amount of indebtedness. As of December 31, 2021, we had $374.9 million of debt outstanding, net of discounts and deferred financing costs (not including finance lease obligations). After giving effect to our borrowing base, we had approximately $205.6 million of availability under our 2019 ABL Facility (as defined herein).
Our substantial indebtedness could have important consequences. For example, it could:
•adversely affect the market price of our common stock;
•increase our vulnerability to interest rate increases and general adverse economic and industry conditions;
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•require us to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness, thereby reducing the availability of our cash flow to fund working capital, capital expenditures and other general corporate purposes, including acquisitions;
•limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
•limit our ability to obtain additional financing on satisfactory terms to fund our working capital requirements, capital expenditures, acquisitions, investments, debt service requirements and other general corporate requirements; and
•place us at a competitive disadvantage compared to our competitors that have less debt.
In addition, we cannot assure you that we will be able to refinance any of our debt, or that we will be able to refinance our debt on commercially reasonable terms. If we were unable to make payments or refinance our debt or obtain new financing under these circumstances, we would have to consider other options, such as:
•sales of assets;
•sales of equity; or
•negotiations with our lenders to restructure the applicable debt.
Our debt instruments may restrict, or market or business conditions may limit, our ability to use some of our options.
Despite our indebtedness levels, we may still be able to incur additional debt, which could further exacerbate the risks associated with our leverage.
We and our subsidiaries may be able to incur additional indebtedness in the future. The terms of the credit agreements that govern the 2019 ABL Facility and the 2018 Term Loan Facility (as defined herein and, together with the 2019 ABL Facility, the “Senior Secured Debt Facilities”) permit us to incur additional indebtedness, subject to certain limitations. If new indebtedness is added to our and our subsidiaries’ current debt levels, the related risks that we and they now face would intensify. See Part II, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Principal Debt Agreements” for further details.
The agreements governing our indebtedness contain operating covenants and restrictions that limit our operations and could lead to adverse consequences if we fail to comply with them.
The agreements governing our indebtedness contain certain operating covenants and other restrictions relating to, among other things, limitations on indebtedness (including guarantees of additional indebtedness) and liens, mergers, consolidations and dissolutions, sales of assets, investments and acquisitions, dividends and other restricted payments, repurchase of shares of capital stock and options to purchase shares of capital stock and certain transactions with affiliates. In addition, our Senior Secured Debt Facilities include certain financial covenants.
The restrictions in the agreements governing our indebtedness may prevent us from taking actions that we believe would be in the best interest of our business and may make it difficult for us to successfully execute our business strategy or effectively compete with companies that are not similarly restricted. We may also incur future debt obligations that might subject us to additional restrictive covenants that could affect our financial and operational flexibility.
Failure to comply with these financial and operating covenants could result from, among other things, changes in our results of operations, the incurrence of additional indebtedness, declines in the pricing of our services and products, difficulties in implementing cost reduction initiatives, difficulties in implementing our overall business strategy or changes in general economic conditions, which may be beyond our control. The breach of any of these covenants or restrictions could result in a default under the agreements that govern these facilities that would permit
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the lenders to declare all amounts outstanding thereunder to be due and payable, together with accrued and unpaid interest. If we are unable to repay such amounts, lenders having secured obligations could proceed against the collateral securing these obligations. The collateral includes the capital stock of our domestic subsidiaries and substantially all of our and our subsidiaries’ other tangible and intangible assets, subject in each case to certain exceptions. This could have serious consequences on our financial condition and results of operations and could cause us to become bankrupt or otherwise insolvent. In addition, these covenants may restrict our ability to engage in transactions that we believe would otherwise be in the best interests of our business and stockholders.
See Part II, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Principal Debt Agreements” for further details.
Substantially all of our debt is variable rate and increases in interest rates could negatively affect our financing costs and our ability to access capital.
We have exposure to future interest rates based on the variable rate debt under the Senior Secured Debt Facilities, and to the extent we raise additional debt in the capital markets to meet maturing debt obligations, to fund our capital expenditures and working capital needs and to finance future acquisitions. Daily working capital requirements are typically financed with operational cash flow and through borrowings under our 2019 ABL Facility, if needed. The interest rate on these borrowing arrangements is generally determined from the inter-bank offering rate at the borrowing date plus a pre-set margin. Although we employ risk management techniques to hedge against interest rate volatility, significant and sustained increases in market interest rates could materially increase our financing costs and negatively impact our reported results.
In addition, in certain circumstances, our variable rate indebtedness uses the London Interbank Offer Rate (“LIBOR”) as a benchmark for establishing the interest rate. The LIBOR has been subject of national, international, and other regulatory guidance and proposals for reform. In July 2017, the U.K. Financial Conduct Authority (the “FCA”) announced that it intends to stop persuading or compelling banks to submit rates for calculation of LIBOR after 2021. These reforms and other pressures may cause LIBOR to disappear entirely or to perform differently than in the past. The consequences of these developments cannot be entirely predicted, but could include an increase in our financing costs and our ability to access capital. On March 5, 2021, the ICE Benchmark Administration, which administers LIBOR, and the FCA announced that all LIBOR settings will either cease to be provided by any administrator, or no longer be representative immediately after December 31, 2021, for all non-U.S. dollar LIBOR settings and one-week and two-month U.S. dollar LIBOR settings, and immediately after June 30, 2023 for the remaining U.S. dollar LIBOR settings (the “LIBOR Announcement”).
These reforms and other pressures may cause LIBOR to disappear entirely or to perform differently than in the past. At this time, no consensus exists as to what rate or rates will become accepted alternatives to LIBOR, although on July 29, 2021, the Alternative Reference Rates Committee (“ARRC”), a U.S.-based group convened by the U.S. Federal Reserve Board and the Federal Reserve Bank of New York, formally recommended the Secured Overnight Financing Rate (“SOFR”) as its preferred replacement rate for LIBOR. Given the inherent differences between LIBOR and SOFR, or any other alternative benchmark rate that may be established, there are many uncertainties regarding a transition from LIBOR, including but not limited to the need to amend all contracts with LIBOR as the referenced rate and how this will impact the cost of variable rate debt and certain derivative financial instruments, or whether the COVID-19 pandemic will have further effect on LIBOR transition plans. In addition, SOFR or other replacement rates may fail to gain market acceptance. The elimination of LIBOR or any other changes or reforms to the determination or supervision of LIBOR could have an adverse impact on the market value of and/or transferability of any LIBOR-linked securities, loans, and other financial obligations or extensions of credit held by or due to us or on our overall financial condition or results of operations.
For certain U.S. dollar borrowings, our Senior Secured Debt Facilities currently bear interest at variable interest rates that use LIBOR. No modification has been made yet to our Senior Secured Debt Facilities as it pertains to USD borrowings as a result of the LIBOR Announcement, though changes will be required in the future. Currently, it is anticipated that the new benchmark for these USD borrowings will be SOFR. The shift to SOFR from LIBOR is complex and may adversely affect our business, financial condition, results of operations, liquidity
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and cash flows. The consequences of these developments cannot be entirely predicted, but could include an increase in our financing costs and our ability to access capital. We do not expect the discontinuation of LIBOR as a reference rate in our debt agreements to have a material adverse effect on our financial position or materially affect our interest expense.
Disruptions in the capital and credit markets, continued low commodity prices, our debt level and other factors may restrict our ability to raise capital on favorable terms, or at all.
Disruptions in the capital and credit markets (which have and may continue to be impact by COVID-19), in particular with respect to companies in the energy sector, could limit our ability to access these markets or may significantly increase our cost to borrow. Continued low commodity prices, among other factors, have caused some lenders to increase interest rates, enact tighter lending standards which we may not satisfy as a result of our debt level or otherwise, refuse to refinance existing debt at maturity on favorable terms, or at all, and in certain instances have reduced or ceased to provide funding to borrowers. If we are unable to access the capital and credit markets on favorable terms or at all, it could adversely affect our business, financial condition and results of operations.
Ability to use net operating loss carryforwards to offset future taxable income for U.S. federal income tax purposes is subject to limitation under Section 382 of the Internal Revenue Code, and NOLs and other tax attributes is subject to reduction, causing less NOL or tax deductions to be available to offset future taxable income for U.S. federal income tax purpose.
Under U.S. federal income tax law, a corporation is generally permitted to deduct from taxable income net operating losses (“NOLs”) carried forward from prior years. As of December 31, 2021, we reported consolidated federal NOL carryforwards of approximately $1.5 billion of which $842.1 million are pre-change NOL's subject to limitation. Our ability to utilize our NOL carryforwards to offset future taxable income and to reduce U.S. federal income tax liability is subject to certain requirements and restrictions. In general, under Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”), a corporation that undergoes an “ownership change” is subject to limitations on its ability to utilize its pre-change NOLs to offset future taxable income. An ownership change generally occurs if one or more stockholders (or groups of stockholders) who are each deemed to own at least 5% of our stock have aggregate increases in their ownership of such stock of more than 50 percentage points over such stockholders’ lowest ownership percentage during the testing period (generally a rolling three year period). We believe we experienced an ownership change in October 2019 as a result of the C&J Merger. We also believe we experienced an ownership change in January 2017 as a result of the implementation of the IPO. Thus our pre-change NOLs are subject to limitation under Section 382 of the Code as a result. Such limitation may cause U.S. federal income taxes to be paid earlier than otherwise would be paid if such limitation were not in effect and could cause a portion of our pre-change NOLs generated prior to 2018 to expire unused, in each case reducing or eliminating the benefit of such NOLs. Similar rules and limitations may apply for state income tax purposes.
Risks Related to Our Common Stock
The price of our common stock may be volatile or may decline regardless of our operating performance, and our stockholders may not be able to resell their shares at or above the public offering price.
The market price for our common stock is volatile. In addition, the market price of our common stock may fluctuate significantly in response to a number of factors, most of which we cannot control, including:
•the failure of securities analysts to cover, or continue to cover, our common stock or changes in financial estimates by analysts;
•changes in, or investors’ perception of, the oil field services industry, including hydraulic fracturing;
•the activities of competitors;
•future issuances and sales of our common stock, including in connection with acquisitions;
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•our quarterly or annual earnings or those of other companies in our industry;
•the public’s reaction to our press releases, our other public announcements and our filings with the SEC;
•regulatory or legal developments in the U.S.;
•litigation involving us, our industry, or both; and
•general economic conditions, including increased levels of inflation.
In addition, the stock market often experiences extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of a particular company. These broad market fluctuations and industry factors may materially reduce the market price of our common stock, regardless of our operating performance.
Because we do not currently pay dividends, our stockholders may not receive any return on investment, unless they sell their common stock for a price greater than that which they paid for it.
We do not currently pay dividends, and our stockholders do not have contractual or other rights, to receive dividends. Our board of directors may, in its discretion, modify or repeal our dividend policy. The declaration and payment of dividends depends on various factors, including: our net income, financial condition, cash requirements, future prospects and other factors deemed relevant by our board of directors.
In addition, we are a holding company that does not conduct any business operations of our own. As a result, we would be dependent upon cash dividends and distributions and other transfers from our subsidiaries to make dividend payments. Our subsidiaries’ ability to pay dividends is restricted by agreements governing their debt instruments and may be restricted by agreements governing any of our subsidiaries’ future indebtedness. Furthermore, our subsidiaries are permitted under the terms of their debt agreements to incur additional indebtedness that may severely restrict or prohibit the payment of dividends. See Part II, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources.”
Under the Delaware General Corporation Law (the “DGCL”), our board of directors may not authorize payment of a dividend unless it is either paid out of our surplus, as calculated in accordance with the DGCL, or if we do not have a surplus, it is paid out of our net profits for the fiscal year in which the dividend is declared and/or the preceding fiscal year.
We may not have an active capital return program, and such programs may not have the desired effect.
Although our board of directors has approved share repurchase programs in the past, they generally have not obligated us to repurchase any specific dollar amount or to acquire any specific number of shares. The timing and amount of repurchases, if any, would depend upon several factors, including market and business conditions, the trading price of our common stock and the nature of other investment opportunities. Any future repurchase program may be limited, suspended or discontinued at any time without prior notice. In addition, repurchases of our common stock pursuant to a share repurchase program could cause our stock price to be higher than it would be in the absence of such a program and could potentially reduce the market liquidity for our stock. Furthermore, a share repurchase program could diminish our cash reserves, which may impact our ability to finance future growth and to pursue possible future strategic opportunities and acquisitions. Although share repurchase programs are intended to enhance long-term stockholder value, there is no assurance that it will do so and short-term stock price fluctuations could reduce the program’s effectiveness.
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Our stockholders may be diluted by the future issuance of additional common stock in connection with our equity incentive plans, acquisitions or otherwise.
We have 243,794,695 shares of common stock authorized but unissued under our certificate of incorporation. We will be authorized to issue these shares of common stock and options, rights, warrants and appreciation rights relating to common stock for consideration and on terms and conditions established by our board of directors in its sole discretion, whether in connection with acquisitions or otherwise. As of December 31, 2021, we have 7,844,941 shares of our common stock available for award that may be issued under our equity incentive plans. Any common stock that we issue, including under our equity incentive plans or other equity incentive plans that we may adopt in the future, may result in additional dilution to our stockholders.
In the future, we may also issue our securities, including shares of our common stock, in connection with investments or acquisitions. We regularly evaluate potential acquisition opportunities, including ones that would be significant to us, and at any one time we may be participating in processes regarding several potential acquisition opportunities, including ones that would be significant to us. We cannot predict the timing of any contemplated transactions, and none are currently probable. The number of shares of our common stock issued in connection with an investment or acquisition could constitute a material portion of our then-outstanding shares of common stock. Any issuance of additional securities in connection with investments or acquisitions may result in additional dilution to our stockholders.
Keane Investor and Cerberus own a significant amount of our common stock and continue to have influence over us, which could limit your ability to influence the outcome of key transactions, including a change of control.
Cerberus currently controls approximately 16.3% of our common stock. Even though Cerberus no longer controls a majority of our common stock, Cerberus continues to have influence over us, including the election of our directors, determination of our corporate and management policies and determination of the outcome of any corporate transaction or other matter submitted to our stockholders for approval, including potential mergers or acquisitions, asset sales and other significant corporate transactions. Two of our ten directors are employees of, appointees of, or advisors to, members of Cerberus. The interests of Cerberus may not coincide with the interests of other holders of our common stock. For example, the concentration of ownership held by Cerberus could delay, defer or prevent a change of control of our company or impede a merger, takeover or other business combination that may otherwise be favorable for us. Additionally, Cerberus is in the business of making investments in companies and may, from time to time, acquire and hold interests in businesses that compete directly or indirectly with us. Cerberus may also pursue, for its own members’ accounts, acquisition opportunities that may be complementary to our business, and as a result, those acquisition opportunities may not be available to us. So long as Cerberus continues to directly or indirectly own a significant amount of our equity, Cerberus will continue to be able to substantially influence or effectively control our ability to enter into corporate transactions.
In addition, if Cerberus through Keane Investor decides to sell substantial amounts of our common stock in the public market, the market price of our common stock could decrease. The perception in the public market that Keane Investor might sell shares of common stock could also create a perceived overhang and depress our market price.
Provisions in our charter documents, certain agreements governing our indebtedness, our Stockholders’ Agreement (as defined herein) and Delaware law could make acquiring us more difficult and may prevent attempts by our stockholders to replace or remove our current management, even if beneficial to our stockholders.
Provisions in our certificate of incorporation, our bylaws and our Stockholders’ Agreement, may discourage, delay or prevent a merger, acquisition or other change in control that some stockholders may consider favorable, including transactions in which our stockholders might otherwise receive a premium for their shares of our common stock. These provisions could also limit the price that investors might be willing to pay in the future for shares of our common stock, possibly depressing the market price of our common stock.
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In addition, these provisions may frustrate or prevent any attempts by our stockholders to replace members of our board of directors. Because our board of directors is responsible for appointing the members of our management team, these provisions could in turn affect any attempt by our stockholders to replace members of our management team. Examples of such provisions are as follows:
•on or after such date that Keane Investor and its respective Affiliates (as defined in Rule 12b-2 of the Exchange Act, or any person who is an express assignee or designee of Keane Investor’s respective rights under our certificate of incorporation (and such assignee’s or designee’s Affiliates)) (of these entities, the entity that is the beneficial owner of the largest number of shares is referred to as the “Designated Controlling Stockholder”) ceases to own, in the aggregate, at least 50% of the then-outstanding shares of our common stock (the “50% Trigger Date”),the authorized number of our directors may be increased or decreased only by the affirmative vote of two-thirds of the then-outstanding shares of our common stock or by resolution of our board of directors;
•on or after the 50% Trigger Date, our stockholders may only amend our bylaws with the approval of at least two-thirds of all of the outstanding shares of our capital stock entitled to vote;
•the manner in which stockholders can remove directors from the board will be limited;
•on or after the 50% Trigger Date, stockholder actions must be effected at a duly called stockholder meeting and actions by our stockholders by written consent are prohibited;
•from and after such date that the Designated Controlling Stockholder ceases to own, in the aggregate, at least 35% of the then-outstanding shares of our common stock (the “35% Trigger Date”), advance notice requirements for stockholder proposals that can be acted on at stockholder meetings and nominations to our board of directors will be established;
•who may call stockholder meetings is limited;
•requirements on any stockholder (or group of stockholders acting in concert), other than, prior to the 35% Trigger Date, the Designated Controlling Stockholder, who seeks to transact business at a meeting or nominate directors for election to submit a list of derivative interests in any of our Company’s securities, including any short interests and synthetic equity interests held by such proposing stockholder;
•requirements on any stockholder (or group of stockholders acting in concert) who seeks to nominate directors for election to submit a list of “related party transactions” with the proposed nominee(s) (as if such nominating person were a registrant pursuant to Item 404 of Regulation S-K, and the proposed nominee was an executive officer or director of the “registrant”); and
•our board of directors is authorized to issue preferred stock without stockholder approval, which could be used to institute a “poison pill” that would work to dilute the stock ownership of a potential hostile acquirer, effectively preventing acquisitions that have not been approved by our board of directors.
Our certificate of incorporation authorizes our board of directors to issue up to 50,000,000 shares of preferred stock. The preferred stock may be issued in one or more series, the terms of which may be determined by our board of directors at the time of issuance or fixed by resolution without further action by the stockholders. These terms may include voting rights, preferences as to dividends and liquidation, conversion rights, redemption rights and sinking fund provisions. The issuance of preferred stock could diminish the rights of holders of our common stock, and therefore, could reduce the value of our common stock. In addition, specific rights granted to holders of preferred stock could be used to restrict our ability to merge with, or sell assets to, a third party. The ability of our board of directors to issue preferred stock could delay, discourage, prevent or make it more difficult or costly to acquire or effect a change in control, thereby preserving the current stockholders’ control.
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In addition, under the agreements governing the Senior Secured Debt Facilities, a change in control may lead the lenders and/or holders to exercise remedies such as acceleration of the obligations thereunder, termination of their commitments to fund additional advances and collection against the collateral securing such obligations.
In connection with the Keane IPO, Keane entered into a Stockholders’ Agreement with Keane Investor. This stockholders’ agreement was amended and restated in conjunction with the C&J Merger (as amended and restated, the “Stockholders’ Agreement”) and provides that, except as otherwise required by applicable law, from the date on which (a) Keane Investor or, in the event a Cerberus Holder no longer holds Company shares through Keane Investor, Cerberus Holder has beneficial ownership of at least 12.5% or greater of the aggregate number of company shares then outstanding, Keane Investor or, in the event Cerberus Holder no longer holds company shares through Keane Investor, Cerberus Representative shall have the right to designate to the board of directors two individuals who satisfy the Director Requirements; and (b) Keane Investor or, in the event Cerberus Holder no longer holder company shares through Keane Investor, Cerberus Holder has beneficial ownership of less than 12.5% but at least 7.5% of the aggregate number of company shares then outstanding, Keane Investor or, in the event Cerberus Holder no longer holds company shares through Keane Investor, Cerberus Representative shall have the right to designate to the board of directors one individual who satisfies the Director Requirements. The ability of Keane Investor or a Holder to appoint one or more directors could make an acquisition of us more difficult and may prevent attempts by our stockholders to replace or remove our current management, even if beneficial to our stockholders.
Our certificate of incorporation and bylaws designate the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers or other employees.
Our certificate of incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will be the exclusive forum for: (a) any derivative action or proceeding brought on our behalf; (b) any action asserting a claim for breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders; (c) any action asserting a claim arising pursuant to any provision of the DGCL, our certificate of incorporation or our bylaws; or (d) any action asserting a claim governed by the internal affairs doctrine. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock is deemed to have received notice of and consented to the foregoing provisions. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds more favorable for disputes with us or our directors, officers or other employees, which may discourage such lawsuits against us and our directors, officers and employees. Alternatively, if a court were to find this choice of forum provision inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition, prospects or results of operations.
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Item 1B. Unresolved Staff Comments
None.
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Item 2. Properties
Properties
We lease office space for our principal executive headquarters, which is located at 3990 Rogerdale Rd., Houston, Texas 77042, and for our engineering and technology center at 8301 New Trails Dr., The Woodlands, Texas. We also own property for our maintenance facilities at 1214 Gas Plant Rd., San Angelo, Texas 76904.
In addition, we own or lease numerous other smaller facilities and administrative offices across the geographic regions in which we operate to support our ongoing operations, including district offices, local sales offices, yard facilities and temporary facilities to house employees in regions where infrastructure is limited. Our leased properties are subject to various lease terms and expirations. We believe that our existing facilities are adequate for our operations and our locations allow us to efficiently serve our customers. However, we continue to evaluate the purchase or lease of additional properties or the consolidation of our properties, as our business requires. We do not believe that any single facility is material to our operations and, if necessary, we could readily obtain a replacement facility.
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Item 3. Legal Proceedings
The information in response to this item is incorporated herein by reference from Note (18) Commitments and Contingencies of Part II, “Item 8. Financial Statements and Supplementary Data” of this Annual Report on Form 10-K.
Item 4. Mine Safety Disclosures
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
Market Information
Our common stock trades on the NYSE under the symbol “NEX”. On February 18, 2022, the last reported sales price of our common stock on the NYSE was $7.19 per share.
Comparative Stock Performance Graph
The information contained in this Comparative Stock Performance Graph section shall not be deemed to be “soliciting material” or “filed” or incorporated by reference in future filings with the SEC, or subject to the liabilities of Section 18 of the Exchange Act, except to the extent that we specifically incorporate it by reference into a document filed under the Securities Act or the Exchange Act.
The graph below compares the cumulative total stockholder return on our common stock, the cumulative total return on the Standard & Poor’s 500 Stock Index, the Standard & Poor’s MidCap Index, the Oilfield Service Index and a composite average of publicly traded peer companies (Nine Energy Services, Inc., FTS International, Inc., Liberty Oilfield Services Inc., Patterson-UTI Energy, Inc., ProPetro Holding Corp., U.S. Well Services, Inc., and RPC, Inc.), since January 20, 2017.
The graph assumes $100 was invested on January 20, 2017 in our common stock, the Standard & Poor’s 500 Stock Index, the Standard & Poor’s MidCap Index, the Oilfield Service Index and a composite of publicly traded peer companies. The cumulative total return assumes the reinvestment of all dividends. We elected to include the stock performance of a composite of our publicly traded peers, as we believe it is an appropriate benchmark for our line of business/industry.
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Holders
As of February 18, 2022, we had 243,794,695 shares of common stock issued and outstanding, held by approximately 12 registered holders. The number of registered holders does not include holders that have common stock held for them in “street name,” meaning that the stock is held for their accounts by a broker or other nominee.
Dividends
We have not paid any cash dividends on our common stock to date. However, our board of directors may consider the payment of dividends in the future based on our levels of profitability and indebtedness. The declaration and payment of any future dividends will be at the sole discretion of our board of directors and will depend upon, among other things, our earnings, financial condition, capital requirements, level of indebtedness, contractual restrictions with respect to the payment of dividends and other considerations that our board of directors deems relevant. Our board of directors may decide, in its discretion, at any time, to modify or repeal the dividend policy or discontinue entirely any payment of dividends.
The ability of our board of directors to declare a dividend is also subject to limits imposed by Delaware corporate law. Under Delaware law, our board of directors and the boards of directors of our corporate subsidiaries incorporated in Delaware may declare dividends only to the extent of our “surplus,” which is defined as total assets at fair market value minus total liabilities, minus statutory capital, or if there is no surplus, out of net profits for the fiscal year in which the dividend is declared and/or the preceding fiscal year.
Purchases of Equity Securities
| Issuer Purchases of Equity Securities | ||||||||||||||||||||||||||
| Settlement Period | (a) Total Number of Shares Purchased(1) | (b) Average Price Paid per Share | (c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | (d) Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs | ||||||||||||||||||||||
| October 1, 2021 through October 31, 2021 | 1,986 | $ | 4.85 | — | $ | — | ||||||||||||||||||||
| November 1, 2021 through November 30, 2021 | — | $ | — | — | $ | — | ||||||||||||||||||||
| December 1, 2021 through December 31, 2021 | 230,365 | $ | 3.59 | — | $ | — | ||||||||||||||||||||
| Total | 232,351 | $ | 3.60 | — | $ | — | ||||||||||||||||||||
(1) Consists of shares that were withheld by us to satisfy tax withholding obligations of employees that arose upon the vesting of restricted shares. The value of such shares is based on the closing price of our common shares on the vesting date.
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Item 6. Reserved
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes included within Part II, “Item 8. Financial Statements and Supplementary Data” in this Annual Report on Form 10-K. For additional information related to forward looking statements or information related to the basis of presentation and comparability of financial information, please see “Cautionary Statement Regarding Forward-Looking Statements and Information” and “Basis of Presentation in this Annual Report on Form 10-K”, both of which immediately follow the table of contents of this Form 10-K.
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Business Overview
NexTier Oilfield Solutions Inc. is a predominantly U.S. land oilfield service company, with a diverse set of well completion and production services across a variety of active and demanding basins. We have a history of growth through acquisition, including (i) our 2019 transaction with C&J, a publicly traded Delaware corporation, and (ii) our 2021 acquisition of Alamo, a pressure pumper focused in the Permian. This history impacts the comparability of our operational results from year to year. See Part I, “Item 1. Business” of this Annual Report for an overview of our history, including additional information on certain of the acquisitions noted above, including the C&J Merger and the Alamo Acquisition, and business environment. Additional information on the C&J Merger and the Alamo Acquisition can also be found in Note (3) Mergers and Acquisitions of Part II, “Item 8. Financial Statements and Supplemental Data.”
Industry Overview and Drivers in 2021
We provide our services in several of the most active basins in the United States, including the Permian, the Marcellus Shale/Utica, the Eagle Ford, Haynesville and the Bakken/Rockies. The high density of our operations in the basins in which we are most active provides us the opportunity to leverage our fixed costs and to quickly respond with what we believe are highly efficient, integrated solutions that are best suited to address customer requirements.
Activity within our business segments is significantly impacted by spending on upstream exploration, development and production programs by our customers. Thus, our financial performance is affected by rig and well counts in North America, as well as oil and natural gas prices, which are summarized in the tables below. Also influencing our activity is the status of the global economy, which impacts oil and natural gas demand. Some of the more significant determinants of current and future spending levels of our customers are oil and natural gas prices, global oil supply, the world economy, the availability of credit, government regulation and global stability, which together drive worldwide drilling activity.
During 2021, global crude markets continued to recover from the COVID-19 pandemic induced dual supply and demand shock that emerged in the first quarter of 2020. Crude prices were significantly higher in 2021, the result of both higher demand relative to the 2020 trough as well as a generally undersupplied market. This translated into higher completions activity in 2021 relative to 2020. Crude oil prices have improved from their 2020 lows, which if maintained, we believe could drive a healthy level of investment and activity in U.S. shale, if macro-economic conditions continue to improve.
There has been some attrition through consolidation and other events that have made some progress in realigning frac supply with demand. We believe frac supply utilization improved significantly by the end of 2021 and may be nearing 90% as we enter 2022. Against this backdrop, pricing for our services has improved considering demand for our services has remained strong. Contributing to the tightness, horsepower intensity for each fleet continues to grow as our industry adopts more complex completion techniques; as horsepower demand returns, we believe existing supply will be fully utilized across fewer fleets.
We have focused on reducing our marketed fleet to a level that we believe is more in-line with long term demand and with our strategy to harvest the investments made in our traditional fleets, while growing the portion of our fleet that offers better pricing and a lower emissions profile. Subsequent to the C&J merger, through 2020 we significantly reduced our horsepower down to 1.8 million. During the third quarter of 2021, the acquisition of Alamo added approximately 0.5 million additional horsepower to our fleet, which was then partially offset in the fourth quarter of 2021 through the international sale and decommisioning of approximately 0.2 million additional horsepower. The major components from the decommissioned fleets have and will continue to be used over time as part of our maintenance inventory. Once consumed, we intend to cut up the frames and permanently remove them from our marketed base of equipment. Our nameplate capacity at the end of 2021 totaled approximately 2.1 million horsepower.
The following table shows the average historical oil and natural gas prices for WTI and Henry Hub natural gas:
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The historical average U.S. rig counts based on the weekly Baker Hughes Incorporated rig count information were as follows:
| Year Ended December 31, | ||||||||||||||||||||
| Product Type | 2021 | 2020 | 2019 | |||||||||||||||||
| Oil | 380 | 346 | 773 | |||||||||||||||||
| Natural Gas | 97 | 85 | 169 | |||||||||||||||||
| Other | 1 | 2 | 1 | |||||||||||||||||
| Total | 478 | 433 | 943 | |||||||||||||||||
| Year Ended December 31, | ||||||||||||||||||||
| Drilling Type | 2021 | 2020 | 2019 | |||||||||||||||||
| Horizontal | 431 | 384 | 826 | |||||||||||||||||
| Vertical | 22 | 20 | 54 | |||||||||||||||||
| Directional | 25 | 29 | 63 | |||||||||||||||||
| Total | 478 | 433 | 943 | |||||||||||||||||
As of January 2022, global liquids demand is expected to average 100.5 million barrels per day in 2022. The EIA anticipates continued growth in the long-term U.S. domestic demand for natural gas, supported by various factors, including (i) increased likelihood of favorable regulatory and legislative initiatives, (ii) increased acceptance of natural gas as a clean and abundant domestic fuel source and (iii) the emergence of low-cost natural gas shale developments. As of January 2022, natural gas demand in the United States is expected to average 82.77 billion cubic feet per day in 2022.
The regions in which we operate, including the Permian, Marcellus Shale / Utica Basins, Haynesville and Eagle Ford, among others, are expected to account for a majority of all new horizontal wells anticipated to be drilled through 2022. As of December 31, 2021, rigs in these basins accounted for approximately 73% of the total, and were up approximately 51% as compared to low total U.S. rig count noted on January 8, 2021.
The current U.S. administration has expressed support for alternative energy sources, reduction of greenhouse gas emissions, the use and dependence on fossil fuels, and efforts addressing climate change. At this time, it remains unclear what impact new actions and policy platforms of the administration may have on our business, our customers, and our industry.
Operating Approach & Strategy
We believe that there is competitive value in providing integrated solutions that align the incentives of operators and service providers. We are pursuing opportunities to leverage our investment in our digital program and diesel substitution technologies (such as duel fuel capabilities), to provide a service strategy targeted at achieving emissions reductions, both for us and our customers. NexTier has been developing and building its digital program for some time, and we have now applied our digital platform to all of our operating fleets. We also launched our new Power Solutions business in 2021, which provides a natural gas treatment and delivery service that will power NexTier’s fleet with field gas or compressed natural gas. This addition seeks to address wellsites where there is not a reliable nearby gas supply, and thus, the full benefit and value of dual fuel or other lower emissions technologies
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may not otherwise be fully realized. To address this situation, we developed an integrated natural gas treatment and delivery solution designed to provide gas sourcing, compression, transport, decompression, treatment, and distribution services for our fracing operations. This integrated strategy will provide our customers with a streamlined approach to driving more sustainable, cost-effective operations at the wellsite.
We believe our integrated approach and proven capabilities enable us to deliver cost-effective solutions for increasingly complex and technically demanding well completion requirements, which include longer lateral segments, higher pressure rates and proppant intensity and multiple fracturing stages in challenging high-pressure formations. In addition, our technical team and our innovation centers, provide us with the ability to supplement our service offerings with engineered solutions specifically tailored to address customers’ completion requirements and unique challenges.
Our revenues are generated by providing services and equipment to customers who operate oil and gas properties and invest capital to drill new wells and enhance production or perform maintenance on existing wells. Our results of operations in our core service lines are driven primarily by five interrelated, fluctuating variables: (1) the drilling, completion and production activities of our customers, which is primarily driven by oil and natural gas prices and directly affects the demand for our services; (2) the price we are able to charge for our services and equipment, which is primarily driven by the level of demand for our services and the supply of equipment capacity in the market; (3) the cost of materials, supplies and labor involved in providing our services, and our ability to pass those costs on to our customers; (4) our activity, or deployed equipment “utilization” levels; and (5) the quality, safety and efficiency of our service execution.
Our operating strategy is focused on maintaining high utilization levels of deployed equipment to maximize revenue generation while controlling costs to gain a competitive advantage and drive returns. We believe that the quality and efficiency of our service execution and aligning with customers who recognize the value that we provide are central to our efforts to support equipment utilization and grow our business.
However, equipment utilization cannot be relied on as wholly indicative of our financial or operating performance due to variations in revenue and profitability from job to job, the type of service to be performed and the equipment, personnel and consumables required for the job, as well as competitive factors and market conditions in the region in which the services are performed. Given the volatile and cyclical nature of activity drivers in the U.S. onshore oilfield services industry, coupled with the varying prices we are able to charge for our services and the cost of providing those services, among other factors, operating margins can fluctuate widely depending on supply and demand at a given point in the cycle.
Historically, our utilization levels have been highly correlated to U.S. onshore spending by our customers. Generally, as capital spending by our customers increases, drilling, completion and production activity also increases, resulting in increased demand for our services, and therefore more days or hours worked (as the case may be). Conversely, when drilling, completion and production activity levels decline due to lower spending by our customers, we generally provide fewer services, which results in fewer days or hours worked (as the case may be). Additionally, during periods of decreased spending by our customers, we may be required to discount our rates or provide other pricing concessions to remain competitive and support deployed equipment utilization, which negatively impacts our revenue and operating margins. During periods of pricing weakness for our services, we may not be able to reduce our costs accordingly, and our ability to achieve any cost reductions from our suppliers typically lags behind the decline in pricing for our services, which could further adversely affect our results. Furthermore, when demand for our services increases following a period of low demand, our ability to capitalize on such increased demand may be delayed while we reengage and redeploy equipment and crews that have been idled during a downturn. The mix of customers that we are working for, as well as limited periods of exposure to the spot market, also impacts our deployed equipment utilization.
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Our Reportable Segments
Prior to the C&J Merger, the Company was organized as two reportable segments. Between the C&J Merger and the divestiture of our well support services business in March of 2020, our business was organized into three reportable segments. Additional information on these transactions can be found in Note (21) Business Segments. As of December 31, 2021, we were organized into two reportable segments, described below. This history impacts the comparability of our operational results from year to year.
•Completion Services, which consists of the following businesses and services lines: (1) hydraulic fracturing; (2) wireline and pumpdown services; and (3) completion support services, which includes our innovation centers and activities.
•Well Construction and Intervention Services, which consists of the following businesses and service lines: (1) cementing services; and (2) coiled tubing services.
Completion Services
The core services provided through our Completion Services segment are hydraulic fracturing, wireline and pumpdown services. As of December 31, 2021, we had approximately 2.1 million of fracturing hydraulic horsepower, 101 wireline trucks and 76 pumpdown units capable of being deployed. Our completion support services are focused on supporting the efficiency, reliability and quality of our operations. Our innovation centers provide in-house manufacturing capabilities that help to reduce operating cost and enable us to offer more technologically advanced and efficiency focused completion services, which we believe is a competitive differentiator. For example, through our innovation centers we manufacture the data control instruments used in our fracturing operations and assemble the perforating guns and addressable switches used in our wireline operations; some of these products are also available for sale to third-parties. The majority of revenue for this segment is generated by our fracturing business.
Well Construction and Intervention Services
The core services provided through our Well Construction and Intervention Services segment are cementing and coiled tubing services. The majority of revenue for this segment is generated by our cementing business. As of December 31, 2021, we had approximately 17 coiled tubing units and 74 cementing units capable of being deployed.
Historical Segment: Well Support Services
On March 9, 2020, we completed a divestiture of the entities and assets comprising our Well Support Services. This segment had focused on post-completion activities at the well site, including rig services, such as workover and plug and abandonment, fluids management services, and other specialty well site services. Our financials for the full year ended December 31, 2020 include operating results of the Well Support Services business prior to its divestiture.
How we calculate utilization for each segment
Our management team monitors asset utilization, among other factors, for purposes of assessing our overall activity levels and customer demand. For our Completion Services segment, asset utilization levels for our own fleets is defined as the ratio of the average number of deployed fleets to the number of total fleets for a given time period. We define active fleets as fleets available for deployment; we consider one of our fleets deployed if the fleet has been put in service at least one day during the period for which we calculate utilization; and we define fully-utilized fleets per month as fleets that were deployed and working with our customers for a significant portion of a given month. As a result, as additional fleets are incrementally deployed, our utilization rate increases. We define industry utilization of fracturing assets as the ratio of the total industry demand of hydraulic horsepower to the total
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available capacity of hydraulic horsepower, in each case as reported by an independent industry source. Our method for calculating the utilization rate for our own fracturing fleets or the industry may differ from the method used by other companies or industry sources which could, for example, be based off a ratio of the total number of days a fleet is put in service to the total number of days in the relevant period. We believe that our measures of utilization, based on the number of deployed fleets, provide an accurate representation of existing, available capacity for additional revenue generating activity.
In our Well Construction and Intervention Services segment, we measure our asset utilization levels for our cementing business primarily by the total number of days that our asset base works on a monthly basis, based on the available working days per month. In our coiled tubing business, we measure certain asset utilization levels by the hour to better understand measures between daylight and 24-hour operations. Both the financial and operating performance of our coiled tubing and cement units can vary in revenue and profitability from job to job depending on the type of service to be performed and the equipment, personnel and consumables required for the job, as well as competitive factors and market conditions in the region in which the services are performed.
In our Well Support Services segment, we measured asset utilization levels primarily by the number of hours our assets work on a monthly basis, based on the available working days per month.
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RESULTS OF OPERATIONS
The following table sets forth our financial results for the year ended December 31, 2021 as compared to the year ended December 31, 2020.
A comparison of our financial results for the year ended December 31, 2020 and for the year ended December 31, 2019 can be found in the "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations" section in our Annual Report on Form 10-K for the fiscal year ended December 31, 2020, filed on February 24, 2021.
Year Ended December 31, 2021 Compared with Year Ended December 31, 2020
| Year Ended December 31, | ||||||||||||||||||||||||||||||||||||||
(Thousands of Dollars) | As a % of Revenue | Variance | ||||||||||||||||||||||||||||||||||||
Description | 2021 | 2020 | 2021 | 2020 | $ | % | ||||||||||||||||||||||||||||||||
| Completion Services | $ | 1,324,888 | $ | 1,046,314 | 93 | % | 87 | % | $ | 278,574 | 27 | % | ||||||||||||||||||||||||||
| Well Construction and Intervention Services | 98,553 | 98,338 | 7 | % | 8 | % | 215 | 0 | % | |||||||||||||||||||||||||||||
| Well Support Services | — | 57,929 | 0 | % | 5 | % | (57,929) | (100 | %) | |||||||||||||||||||||||||||||
Revenue | 1,423,441 | 1,202,581 | 100 | % | 100 | % | 220,860 | 18 | % | |||||||||||||||||||||||||||||
| Completion Services | 1,165,881 | 893,785 | 82 | % | 74 | % | 272,096 | 30 | % | |||||||||||||||||||||||||||||
| Well Construction and Intervention Services | 89,440 | 93,198 | 6 | % | 8 | % | (3,758) | (4 | %) | |||||||||||||||||||||||||||||
| Well Support Services | — | 45,591 | 0 | % | 4 | % | (45,591) | (100 | %) | |||||||||||||||||||||||||||||
Costs of services | 1,255,321 | 1,032,574 | 88 | % | 86 | % | 222,747 | 22 | % | |||||||||||||||||||||||||||||
Depreciation and amortization | 184,164 | 302,051 | 13 | % | 25 | % | (117,887) | (39 | %) | |||||||||||||||||||||||||||||
Selling, general and administrative expenses | 109,404 | 144,147 | 8 | % | 12 | % | (34,743) | (24 | %) | |||||||||||||||||||||||||||||
Merger and integration | 8,709 | 32,539 | 1 | % | 3 | % | (23,830) | (73 | %) | |||||||||||||||||||||||||||||
(Gain) loss on disposal of assets | (28,898) | (14,461) | (2 | %) | (1 | %) | (14,437) | 100 | % | |||||||||||||||||||||||||||||
Impairment | — | 37,008 | 0 | % | 3 | % | (37,008) | (100 | %) | |||||||||||||||||||||||||||||
| Operating loss | (105,259) | (331,277) | (7 | %) | (28 | %) | 226,018 | (68 | %) | |||||||||||||||||||||||||||||
| Other income, net | 12,131 | 6,516 | 1 | % | 1 | % | 5,615 | 86 | % | |||||||||||||||||||||||||||||
| Interest expense | (24,609) | (20,652) | (2 | %) | (2 | %) | (3,957) | 19 | % | |||||||||||||||||||||||||||||
Total other expenses | (12,478) | (14,136) | (1 | %) | (1 | %) | 1,658 | (12 | %) | |||||||||||||||||||||||||||||
| Income tax expense | (1,686) | (1,470) | 0 | % | 0 | % | (216) | 15 | % | |||||||||||||||||||||||||||||
| Net loss | $ | (119,423) | $ | (346,883) | (8 | %) | (29 | %) | $ | 227,460 | (66 | %) | ||||||||||||||||||||||||||
Revenue. Total revenue is comprised of revenue from our Completion Services, Well Construction and Intervention Services and Well Support Services segments. Revenue in 2021 increased by $220.9 million, or 18%, to $1.4 billion from $1.2 billion in 2020. This change in revenue by reportable segment is discussed below.
Completion Services: Completion Services segment revenue increased by $278.6 million, or 27%, to $1.3 billion in 2021 from $1.0 billion in 2020. The segment revenue increase was primarily driven by increases in our fracturing service line, partially offset by decreases in wireline and pumpdown services. The fracturing increase is mostly due to a higher number of fully utilized fleets deployed, increased logistics services, the acquisition of Alamo, and modest pricing recovery. The wireline and pumpdown decrease is primarily attributable to less activity
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in our Northeast and West regions from the strategic decision to reallocate our equipment and resources to regions we believe will be more profitable as the market continues to recover from the COVID-19 pandemic.
Well Construction and Intervention: Well Construction and Intervention Services segment revenue increased by $0.2 million, or 0%, to $98.6 million in 2021 from $98.3 million in 2020. This slight increase in revenue is driven by increased activity and utilization in our cementing services, mostly offset by reductions in coil tubing activity. We made the strategic decision to reduce our geographic coil tubing footprint and will continue to focus on select regions we believe will provide the best opportunities for profitable growth.
Well Support Services: Well Support Services segment revenue decreased by $57.9 million or (100%) to $0.0 million in 2021 from $57.9 million in 2020. In March of 2020 we sold our Well Support Services Segment. For additional information on this transaction, see Note (21) Business Segments of Part II, “Item 8. Financial Statements and Supplementary Data”.
Cost of services. Cost of services in 2021 increased by $222.7 million, or 22%, to $1.3 billion from $1.0 billion in 2020. This increase is primarily due to increased activity as explained in Revenue above, combined with higher sand and freight costs from increased logistics services in our Completion Services segment, increased repair and maintenance expenses related to start-up costs of fleet re-deployments, and input costs inflation.
Equipment Utilization. Depreciation and amortization expense decreased by $117.9 million, or (39%), to $184.2 million in 2021 from $302.1 million in 2020. The change in depreciation and amortization was primarily due to more equipment nearing the end of its useful lives and changes in the estimated useful life of certain of our equipment in the first quarter of 2021, which consisted mostly of increases to the expected life of our fracturing equipment, partially offset by the additional equipment received in the Alamo Acquisition. (Gain) loss on disposal of assets in 2021 increased $14.4 million, to a gain of $28.9 million in 2021 compared to a gain of $14.5 million in 2020. This change was primarily driven by the Company’s divesting of diesel-powered frac equipment and other non-core assets to fund conversions of equipment to be powered by natural gas.
Selling, general and administrative expense. Selling, general and administrative (“SG&A”) expense, which represents costs associated with managing and supporting our operations, decreased by $34.7 million, or (24%), to $109.4 million in 2021 from $144.1 million in 2020, primarily due to the $24.9 million accrual reduction for our regulatory audit estimate, reduction in property taxes, business transformation results to structurally drive out costs and increase efficiencies in our support functions, partially offset by increased bonus incentive plans and the acquisition of Alamo.
Merger and integration expense. Merger and integration expense decreased by $23.8 million, or (73%), to $8.7 million in 2021 from $32.5 million in 2020. The decrease in merger and integration expense in 2021 is primarily due to the completion of the C&J Merger associated costs in 2020, which consisted mostly of professional services, severance costs, and facility consolidation, partially offset by Alamo Acquisition costs in 2021.
Other income, net. Other income, net, in 2021 increased by $5.6 million, or 86%, to $12.1 million in 2021 from $6.5 million in 2020. This change was primarily due to a $10.4 million gain recognized as a result of the insurance proceeds received for an accidental fire in the Permian Basin, which resulted in a complete loss of equipment, partially offset by a $6.0 million gain on a financial investment the Company acquired in 2020.
Interest expense, net. Interest expense, net of interest income, increased by $4.0 million, or 19%, to $24.6 million in 2021 from $20.7 million in 2020. This change was primarily attributable to an increase in the Company’s finance leases as part of the Alamo Acquisition.
Effective tax rate. Our effective tax rate on continuing operations in 2021 was (1.43)% for $1.7 million of recorded income tax expense, as compared to (0.43)% for $1.4 million of recorded income tax expense in 2020. For 2021, the difference between the effective tax rate and the U.S. federal statutory rate is due to state taxes, foreign withholding taxes and a change in valuation allowance. For 2020, the effective rate was primarily made up of state taxes and tax benefits derived from the current period operating income offset by a valuation allowance. As a result
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of market conditions and their corresponding impact on our business outlook, we determined that a valuation allowance was appropriate as it is not more likely than not that we will utilize our net deferred tax assets. The remaining tax impact not offset by a valuation allowance is related to indefinite-lived assets.
2022 Strategy
We face many challenges and risks in the industry in which we operate. Although many factors contributing to these risks are beyond our ability to control, we continuously monitor these risks and have taken steps to mitigate them to the extent practicable. In addition, while we believe that we are well positioned to capitalize on available growth opportunities, we may not be able to achieve our business objectives and, consequently, our results of operations may be adversely affected. Please read the factors described in the sections titled “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” in Part I, Item 1A. of this Annual Report for additional information about the known material risks that we face.
Operating During a Pandemic
In response to the COVID-19 pandemic, we have implemented measures to focus on the safety of our partners, employees, and the communities in which we operate, while at the same time seeking to mitigate the impact on our financial position and operations. These measures include, but are not limited to, the following:
Taking Care of our Partners and Employees. The safety of our partners and employees continues to be a primary focus. As the COVID-19 pandemic has developed, we have taken numerous steps to help customers and employees comply with current health-expert recommendations, including limitation of social functions and non-essential travel, hygiene protocol education, telecommuting as job responsibilities permit, protocols and procedures focused on establishing a safe work environment, protocol for employees who test positive for COVID-19, and a response and mitigation monitoring process.
Expense Management. With the reduction in revenue during the year ended December 31, 2020 and early 2021, we implemented cost saving initiatives, including (i) adjusting active frac fleet count to align with changing demand; (ii) consolidating our footprint; (iii) delaying non-essential maintenance projects; (iv) reducing or suspending other discretionary spending; (v) restructuring our organization in a way that maximizes our managerial talent with a streamlined team; (vi) reductions of salaries or cash retainers, as applicable, by 20% for our directors and executive officers; and (vi) reducing employee-related costs, including furloughing personnel, pay reductions by 15-20%, and moderating headcount. While many of these cost savings initiatives continue, with the increase in activity, we have been able to put most of our furloughed personnel back to work, and we have begun rolling out a portion of pay reinstatement, with the focus on field level personnel. We recognize that the COVID-19 pandemic and responses thereto also impact our suppliers. To date, we have generally been able to obtain the equipment, parts and supplies necessary to support our operations on a timely basis. While we believe we will be able to make satisfactory alternative arrangements in the event of any interruption in the supply of these materials and/or products by one of our suppliers, this may not always be the case. In addition, certain materials for which we do not currently have long-term supply agreements could experience shortages and significant price increases in the future.
Balance Sheet, Cash Flow and Liquidity Management. We have taken actions to protect liquidity and maintain a strong financial position. As a result of these actions, our cash and cash equivalents balance as of December 31, 2021 was $110.7 million. For additional information on our liquidity and capital resources, see “Liquidity and Capital Resources.”
Fiscal 2022 Objectives
With commodity prices continuing to be volatile, we intend to closely monitor the market and will adjust our approach as the situation develops. At this time, our principal business objective continues to be growing our business and safely providing best-in-class services in all of our operating segments, while delivering stockholder value and maintaining a disciplined capital deployment strategy.
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We are committed to continuing to manage our business in line with demand for our services and make adjustments as necessary to effectively respond to changes in market conditions, customer activity levels, pricing for our services and equipment, and utilization of our deployed equipment and personnel. Our response to the industry's persistent uncertainty is to maintain sufficient liquidity, preserve our conservative capital structure and closely monitor our discretionary spending. We take a measured approach to asset deployment, balancing our view of current and expected customer activity levels with a focus on generating positive returns for our stockholders. Our priorities remain to drive revenue by maximizing deployed equipment utilization, to improve margins through cost controls, to protect and grow our market share by focusing on the quality, safety and efficiency of our service execution, lower emissions, and to ensure that we are strategically positioned to capitalize on constructive market dynamics.
Completion Services
In our Completion Services segment, our strategy remains focused on deploying our market-ready fracturing fleets and integrating more of our wireline and pumpdown units with our deployed fracturing fleets and on a stand-alone basis. We are focused on increasing our dedicated fracturing fleet count with efficient customers that allow us to achieve high equipment utilization, which should result in improved financial performance. As part of this effort, we continuously evaluate new technologies with enhanced capabilities and greater operating efficiency to replace aging equipment within our fracturing fleet as it becomes obsolete or retired. In connection with such ongoing evaluation, we may from time to time enter into agreements for the purchase or lease of such replacement equipment. Additionally, we are also focused on integrating more of our wireline and pumpdown units with our fracturing fleets to increase operational efficiencies and profitability. Notwithstanding the foregoing, current market conditions remain challenging, and our primary focus remains to lower our overall cost structure by aligning with efficient, dedicated customers with deep inventories of work and proven track records of efficient operations, many of which we have created long-term relationships with over the past several years. Subsequent to the Alamo Acquisition, all of Alamo operations have been included within the Completion Services segment.
Furthermore, as discussed in Item 1. Business and Item 7. MD&A Overview, as part of our lower emissions initiatives, we are focused on optimizing gas substitution across our fleet, enabled by digital capabilities like NexHub and MDT controls, and the launch of our power solutions business. We believe that natural gas-powered technologies and digital assisted logistics will be a key method of transitioning to lower emissions operations, which strategy we anticipate will be a key driver of returns.
Well Construction and Intervention Services
In our Well Construction and Intervention Services segment, after significantly reducing our footprint during the second and third quarters of 2020 as we seek to position ourselves for strong operational and financial performance in regions that will support both near-term and long-term levels of activity, our strategy remains focused on deploying our market-ready cementing and coil tubing equipment in focused basins where we expect to generate returns. In our cementing business, even though market conditions remain challenged due to customers releasing drilling rigs and declining E&P capital spending, we remain focused on providing high-quality, timely service and deploying more of our stacked units with efficient customers in our focused basins. In our coiled tubing business, we are focused on market share growth, high quality customer service, and deploying additional market ready units at a low cost in response to increases in demand from our customers. We will stay focused on controlling costs and improving market share with an efficient customer base that plan to maintain stable drilling rig counts and levels of activity in 2022.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity represents a company’s ability to adjust its future cash flows to meet needs and opportunities, both expected and unexpected.
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| (Thousands of Dollars) | ||||||||||||||
| Year Ended December 31, | ||||||||||||||
| 2021 | 2020 | |||||||||||||
Cash | $ | 110,695 | $ | 275,990 | ||||||||||
Debt, net of deferred financing costs and debt discount | $ | 374,885 | $ | 335,540 | ||||||||||
| (Thousands of Dollars) | ||||||||||||||||||||
| Year Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| Net cash provided by (used in) operating activities | $ | (50,787) | $ | 68,885 | $ | 305,463 | ||||||||||||||
| Net cash used in investing activities | $ | (163,201) | $ | (37,844) | $ | (114,100) | ||||||||||||||
| Net cash provided by (used in) financing activities | $ | 48,286 | $ | (9,825) | $ | (16,746) | ||||||||||||||
Significant sources and uses of cash during the year ended December 31, 2021
Sources of cash:
•Financing activities:
–Net cash provided by financing activities for the year ended December 31, 2021 was $48.3 million, which was is an increase of $58.1 million compared to the year ended December 31, 2020. This change was primarily due to the $43.2 million the Company received through our 2021 Equipment Loans and $17.8 million from financing liabilities.
Uses of cash:
•Operating activities:
–Net cash used in operating activities during the year ended December 31, 2021 was $50.8 million, which resulted in a change of $119.7 million compared to the year ended December 31, 2020. The change is primarily due to an increase in commodity prices, additional maintenance expenses related to startup costs required for fleet re-deployments, and inflation. For further discussion, see “Results of Operations”.
•Investing activities:
–Net cash used in investing activities for the year ended December 31, 2021 was $163.2 million, which resulted in increase of $125.4 million compared to the year ended December 31, 2020. The change is primarily due to an increase in purchase of property plant and equipment, deposits on equipment and implementation of software of $64.3 million, a $156.1 million change related to acquisition of business and payment of consideration liability, partially offset by an increase of $37.8 million in proceeds from disposal of assets, $34.4 million in cash received from the WSS notes and $22.9 million in proceeds from insurance recoveries.
Significant sources and uses of cash during the year ended December 31, 2020
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Sources of cash:
•Operating activities:
–Net cash generated by operating activities during the year ended December 31, 2020 of $68.9 million, which was down $236.6 million from 2019. The decrease is primarily due to a decrease in our average number of fully utilized fracturing fleets, combined with decreases in our wireline and pumpdown services. The decreases in all service lines were driven by less activity and price reductions as a result of the continuing impacts from the unforeseen and sudden decline in commodity prices as well as the COVID-19 pandemic that began to impact operations in late first quarter of 2020. For further discussion of these drivers, see “Results of Operations”.
•Financing activities:
–In the first quarter of 2020, the Company drew down $175 million on the 2019 ABL Facility. This borrowing was to provide the Company better flexibility while managing its cash position during the ongoing COVID-19 pandemic.
Uses of cash:
•Investing activities:
–Net cash used in investing activities for the year ended December 31, 2020 consisted primarily of capital expenditures, net of the cash received as part of the sale of the Well Support Services business segment.
•Financing activities:
–Cash used to repay our debt facilities (other than described below), excluding finance leases and interest, during the year ended December 31, 2020 was $3.5 million.
–In the first quarter of 2020, the Company drew down $175 million on the 2019 ABL Facility. This borrowing was to provide the Company better flexibility while managing its cash position during the ongoing COVID-19 pandemic. The borrowing on the 2019 ABL Facility was repaid in full during the second quarter of 2020.
–Cash used to repay our finance leases during the year ended December 31, 2020 was $3.8 million.
–Shares withheld and retired related to stock-based compensation during the year ended December 31, 2020 totaled $2.6 million.
Significant sources and uses of cash during the year ended December 31, 2019
Sources of cash:
•Operating activities:
–Net cash generated by operating activities in 2019 of $305.5 million, which was down $44.8 million from 2018. The decrease was driven primarily by a decline in rig count and fleet utilization, combined with pricing pressures from macroeconomic market conditions, and offset by thoroughness in receiving collections from our customers and controlling costs.
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Uses of cash:
•Operating activities:
–Net cash used in operating activities for the year ended December 31, 2019, included $61.9 million of merger and integration costs in connection with the C&J Merger.
Investing activities:
–Net cash used in investing activities for the year ended December 31, 2019 consisted primarily of capital expenditures. This activity primarily related to our Completion Services segment.
•Financing activities:
–Cash used to repay our debt facilities, excluding leases and interest, during the year ended December 31, 2019 was $3.5 million.
–Cash used to repay our finance leases during the year ended December 31, 2019 was $6.0 million.
–Shares withheld and retired related to share-based compensation during the year ended December 31, 2019 totaled $6.0 million.
Future sources and use of cash
Our primary sources of liquidity have historically included, and we have funded our capital expenditures with, cash flows from operations, proceeds from public offerings of our common stock and borrowings under debt facilities. Our ability to generate future cash flows is subject to a number of variables, many of which are outside of our control, including the drilling, completion and production activity by our customers, which is highly dependent on oil and gas prices. See Part II, “Overview” for additional discussion of certain factors that impact our results and the market challenges within our industry.
Our primary uses of cash are for operating costs, capital expenditures, including acquisitions, and debt service.
We expect capital expenditures in 2022 to be lower than 2021. We remain firmly committed to capital discipline, and putting the Company on course for sustained positive cash flow starting in 2022 is a top priority.
Debt service for the year ended December 31, 2022 is projected to be $53.2 million, of which $13.0 million is related to finance leases. We anticipate our debt service will be funded by cash flows from operations.
Other factors affecting liquidity
Financial position in current market. As of December 31, 2021, we had $110.7 million of cash and a total of $205.6 million available under our 2019 ABL Facility. We currently believe that our cash on hand, cash flow generated from operations and availability under our revolving credit facility will provide sufficient liquidity to cover out estimated short-term (i.e., the next 12 months) and long-term (i.e., beyond the next 12 months) funding needs, including for capital expenditures, debt service, and working capital investments.
Guarantee agreements. Under the 2019 ABL Facility $23.2 million of letters of credit were outstanding as of December 31, 2021.
Customer receivables. In line with industry practice, we bill our customers for our services in arrears and are, therefore, subject to our customers delaying or failing to pay our invoices. The majority of our trade receivables have payment terms of 30 to 60 days or less. In weak economic environments, such as during the continuance of the
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COVID-19 pandemic, we may experience increased delays and failures to pay our invoices due to, among other reasons, a reduction in our customers’ cash flow from operations and their access to the credit markets. If our customers delay paying or fail to pay us a significant amount of our outstanding receivables, it could have a material adverse effect on our liquidity, consolidated results of operations and consolidated financial condition.
Contractual Obligations
In the normal course of business, we enter into various contractual obligations that impact or could impact our liquidity. The table below contains our known contractual commitments as of December 31, 2021.
(Thousands of Dollars) Contractual obligations | Total | 2022 | 2023-2024 | 2025-2026 | 2027+ | |||||||||||||||||||||||||||
Long-term debt, including current portion(1) | $ | 379,604 | $ | 14,738 | $ | 31,220 | $ | 333,646 | $ | — | ||||||||||||||||||||||
Estimated interest payments(2) | 58,002 | 16,273 | 34,286 | 7,443 | — | |||||||||||||||||||||||||||
Finance lease obligations(3) | 41,222 | 13,001 | 27,298 | 923 | — | |||||||||||||||||||||||||||
Operating lease obligations(4) | 34,992 | 8,709 | 9,057 | 5,205 | 12,021 | |||||||||||||||||||||||||||
Purchase commitments(5) | 94,305 | 87,955 | 6,350 | — | — | |||||||||||||||||||||||||||
| Legal contingency | 5,223 | 5,223 | — | — | — | |||||||||||||||||||||||||||
| $ | 613,348 | $ | 145,899 | $ | 108,211 | $ | 347,217 | $ | 12,021 | |||||||||||||||||||||||
(1)Long-term debt represents our obligations under our 2018 Term Loan Facility, exclusive of interest payments. In addition, these amounts exclude $4.7 million of unamortized debt discount and debt issuance costs associated with our 2018 Term Loan Facility and Equipment Loan.
(2)Estimated interest payments are based on debt balances outstanding as of December 31, 2021 and include interest related to the 2018 Term Loan Facility and the 2021 Equipment Loans. Interest rates used for variable rate debt are based on the prevailing current LIBOR.
(3)Finance lease obligations primarily consist of obligations on our finance leases of light weight vehicles and frac equipment.
(4)Operating lease obligations are related to our real estate, rail cars, and light duty vehicles.
(5)Purchase commitments primarily relate to our agreements with vendors for sand purchases and deposits on equipment. The purchase commitments to sand suppliers represent our annual obligations to purchase a minimum amount of sand from vendors. If the minimum purchase requirement is not met, the shortfall at the end of the year is settled in cash or, in some cases, carried forward to the next year.
Principal Debt Agreements
While there were numerous governmental assistance programs in 2020 to provide loans to qualifying companies facing challenges due to COVID-19, the Company did not seek any loans under these programs. Thus, our principal debt arrangements continue to be the 2021 Equipment Loan, 2019 ABL Facility and the 2018 Term Loan Facility described below.
2021 Equipment Loans
Origination. On August 20, 2021, we entered into a Master Loan and Security Agreement (the “Master Agreement”) with Caterpillar Financial Services Corporation.
Structure. Our Master Agreement provides for secured equipment financing term loans in an aggregate amount of up to $46.5 million (the “2021 Equipment Loans”). The 2021 Equipment Loans may be drawn in multiple tranches, with each loan evidenced by a separate promissory note.
Maturity. All tranches under the Master Agreement mature on June 1, 2025.
Interest. Term notes entered into under the Master Agreement will bear interest at a rate of 5.25%.
2019 ABL Facility
Origination. On October 31, 2019, we, and certain of our other subsidiaries as additional
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borrowers and guarantors, entered into a Second Amended and Restated Asset-Based Revolving Credit Agreement (the “2019 ABL Facility”) to the original Asset-Based Revolving Credit Agreement, dated as of February 17, 2017, as amended December 22, 2017.
Structure. Our 2019 ABL Facility provides for a $450.0 million revolving credit facility (with a $100.0 million subfacility for letters of credit), subject to a borrowing base in accordance with the terms agreed between us and the lenders. In addition, subject to approval by the applicable lenders and other customary conditions, the 2019 ABL Facility allows for an additional increase in commitments of up to $200.0 million. The 2019 ABL Facility is subject to customary fees, guarantees of subsidiaries, restrictions and covenants, including certain restricted payments.
Maturity. The loans arising under the initial commitments under the 2019 ABL Facility mature on October 31, 2024. The loans arising under any tranche of extended loans or additional commitments mature as specified in the applicable extension amendment or increase joinder, respectively.
Interest. Pursuant to the terms of the 2019 ABL Facility, amounts outstanding under the 2019 ABL Facility bear interest at a rate per annum equal to, at Keane Group Holdings, LLC’s option, (a) the base rate, plus an applicable margin equal to (x) if the average excess availability is less than 33%, 0.75%, (y) if the average excess availability is greater than or equal to 33% but less than 66%, 0.50% or (z) if the average excess availability is greater than or equal to 66%, 0.25%, or (b) the adjusted LIBOR rate for such interest period, plus an applicable margin equal to (x) if the average excess availability is less than 33%, 1.75%, (y) if the average excess availability is greater than or equal to 33% but less than 66%, 1.50% or (z) if the average excess availability is greater than or equal to 66%, 1.25%.
Financial Covenants. The 2019 ABL Facility requires that, under certain circumstances, the consolidated fixed charge coverage ratio not be lower than 1.0:1.0 as of the last day of the most recently completed four consecutive fiscal quarters for which financial statements were required to have been delivered, including if excess availability (or liquidity if no loan or letter of credit, other than any letter of credit that has been cash collateralized, is outstanding) is less than the greater of (i) 10% of the loan cap and (ii) $30.0 million at any time. As of December 31, 2021, the Company was in compliance with all covenants and the circumstances that would require testing of the consolidated fixed charge coverage ratio had not occurred.
2018 Term Loan Facility
On May 25, 2018, Keane Group and the 2018 Term Loan Guarantors (as defined below) entered into the 2018 Term Loan Facility with each lender from time to time party thereto and Barclays Bank PLC, as administrative agent and collateral agent. The proceeds of the 2018 Term Loan Facility were used to refinance Keane Group’s then-existing term loan facility and to repay related fees and expenses, with the excess proceeds to fund general corporate purposes.
Structure. The 2018 Term Loan Facility provides for a term loan facility in an initial aggregate principal amount of $350.0 million (the loans incurred under the 2018 Term Loan Facility, the “2018 Term Loans”). As of December 31, 2021, there was $337.8 million principal amount of 2018 Term Loans outstanding. In addition, subject to certain customary conditions, the 2018 Term Loan Facility allows for additional incremental term loans to be incurred thereunder in an amount equal to the sum of (a) $200.0 million plus the aggregate principal amount of voluntary prepayments of 2018 Term Loans made on or prior to the date of determination (less amounts incurred in reliance on the capacity described in this subclause (a)), plus (b) an unlimited amount, subject to, (x) in the case of debt secured on a pari passu basis with the 2018 Term Loans, immediately after giving effect to the incurrence thereof, a first lien net leverage ratio being less than or equal to 2.00:1.00, (y) in the case of debt secured on a junior basis with the 2018 Term Loans, immediately after giving effect to the incurrence thereof, a secured net leverage ratio being less than or equal to 3.00:1.00 and (z) in the case of unsecured debt, immediately after giving effect to the incurrence thereof, a total net leverage ratio being less than or equal to 3.50:1.00.
Maturity. May 25, 2025 or, if earlier, the stated maturity date of any other term loans or term commitments.
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Amortization. The 2018 Term Loans amortize in quarterly installments equal to 1.00% per annum of the aggregate principal amount of all initial term loans outstanding.
Interest. The 2018 Term Loans bear interest at a rate per annum equal to, at Keane Group’s option, (a) the base rate plus 2.75%, or (b) the adjusted LIBOR for such interest period (subject to a 1.00% floor) plus 3.75%, subject to, on and after the fiscal quarter ending September 30, 2018, a pricing grid with three 0.25% per annum step-ups and one 0.25% per annum step-down determined based on total net leverage for the relevant period. Following a payment event of default, the 2018 Term Loans bear interest at the rate otherwise applicable to such 2018 Term Loans at such time plus an additional 2.00% per annum during the continuance of such event of default. As of December 31, 2021, there was a $337.8 million principal amount of term loans outstanding (the "2018 Term Loans") at an interest rate of LIBOR plus an applicable margin, which is currently at 4.50%. The 2018 Term Loan Facility is subject to customary fees, guarantees of subsidiaries, events of default, restrictions and covenants, including certain restricted payments. As of December 31, 2021, the Company was in compliance with all covenants.
Prepayments. The 2018 Term Loan Facility is required to be prepaid with: (a) 100% of the net cash proceeds of certain asset sales, casualty events and other dispositions, subject to the terms of an intercreditor agreement between the agent for the 2018 Term Loan Facility and the agent for the 2019 ABL Facility and certain exceptions; (b) 100% of the net cash proceeds of debt incurrences or issuances (other than debt incurrences permitted under the 2018 Term Loan Facility, which exclusion is not applicable to permitted refinancing debt) and (c) 50% (subject to step-downs to 25% and 0%, upon and during achievement of certain total net leverage ratios) of excess cash flow in excess of a certain amount, minus certain voluntary prepayments made under the 2018 Term Loan Facility or other debt secured on a pari passu basis with the 2018 Term Loans and voluntary prepayments of loans under the 2019 ABL Facility to the extent the commitments under the 2019 ABL Facility are permanently reduced by such prepayments.
Guarantees. Subject to certain exceptions as set forth in the definitive documentation for the 2018 Term Loan Facility, the amounts outstanding under the 2018 Term Loan Facility were originally guaranteed by the Company, Keane Frac, LP, KS Drilling, LLC, KGH Intermediate Holdco I, LLC, KGH Intermediate Holdco II, LLC, and Keane Frac GP, LLC, and each subsidiary of the Company that have and will be required to execute and deliver a facility guaranty in the future pursuant to the terms of the 2018 Term Loan Facility (collectively, the “2018 Term Loan Guarantors”).
Security. Subject to certain exceptions as set forth in the definitive documentation for the 2018 Term Loan Facility, the obligations under the 2018 Term Loan Facility are secured by (a) a first-priority security interest in and lien on substantially all of the assets of Keane Group and the 2018 Term Loan Guarantors to the extent not constituting ABL Facility Priority Collateral (as defined below) and (b) a second-priority security interest in and lien on substantially all of the accounts receivable, inventory, and frac iron equipment, and certain other assets and property related to the foregoing including certain chattel paper, investment property, documents, letter of credit rights, payment intangibles, general intangibles, commercial tort claims, books and records and supporting obligations of the borrowers and guarantors under the 2019 ABL Facility (the “ABL Facility Priority Collateral”).
Fees. Certain customary fees are payable to the lenders and the agents under the 2018 Term Loan Facility.
Restricted Payment Covenant. The 2018 Term Loan Facility includes a covenant restricting the ability of the Company and its restricted subsidiaries to pay dividends and make certain other restricted payments, subject to certain exceptions. The 2018 Term Loan Facility provides that the Company and its restricted subsidiaries may, among things, make cash dividends and other restricted payments in an aggregate amount during the life of the facility not to exceed (a) $100.0 million, plus (b) the amount of net proceeds received by Keane Group from the funding of the 2018 Term Loans in excess of the of such net proceeds required to finance the refinancing of the pre-existing term loan facility and pay fees and expenses related thereto and to the entry into the 2018 Term Loan Facility, plus (c) an unlimited amount so long as, after giving effect to such restricted payment, the total net leverage ratio would not exceed 2.00:1.00. In addition, the Company and its restricted subsidiaries may make restricted payments utilizing the Cumulative Credit (as defined below), subject to certain conditions including, if any portion
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of the Cumulative Credit utilized is comprised of amounts under clause (b) of the definition thereof below, the pro forma total net leverage ratio being no greater than 2.50:1.00.
“Cumulative Credit”, generally, is defined as an amount equal to (a) $25.0 million, (b) 50% of consolidated net income of the Company and its restricted subsidiaries on a cumulative basis from April 1, 2018 (which cumulative amount shall not be less than zero), plus (c) other customary additions, and reduced by the amount of Cumulative Credit used prior to such time (whether for restricted payments, junior debt payments or investments).
Affirmative and Negative Covenants. The 2018 Term Loan Facility contains various affirmative and negative covenants (in each case, subject to customary exceptions as set forth in the definitive documentation for the 2018 Term Loan Facility). The 2018 Term Loan Facility does not contain any financial maintenance covenants. As of December 31, 2020, the Company was in compliance with all covenants.
Events of Default. The 2018 Term Loan Facility contains customary events of default (subject to exceptions, thresholds and grace periods as set forth in the definitive documentation for the 2018 Term Loan Facility).
Related Party Transactions
Our board of directors has adopted a written policy and procedures (the “Related Party Policy”) for the review, approval and ratification of the related party transactions by the independent members of the audit and risk committee of our board of directors. For purposes of the Related Party Policy, a “Related Party Transaction” is any transaction, arrangement or relationship or series of similar transactions, arrangements or relationships (including the incurrence or issuance of any indebtedness or the guarantee of indebtedness) in which (1) the aggregate amount involved will or may be reasonably expected to exceed $120,000 in any fiscal year, (2) the company or any of its subsidiaries is a participant, and (3) any Related Party (as defined herein) has or will have a direct or indirect material interest. All Related Party Transactions will be reviewed in accordance with the standards set forth in the Related Party Policy after full disclosure of the Related Party’s interests in the transaction.
The Related Party Policy defines “Related Party” as any person who is, or, at any time since the beginning of the Company’s last fiscal year, was (1) an executive officer, director or nominee for election as a director of the Company or any of its subsidiaries, (2) a person with greater than five percent (5%) beneficial interest in the Company, (3) an immediate family member of any of the individuals or entities identified in (1) or (2) of this paragraph, and (4) any firm, corporation or other entity in which any of the foregoing individuals or entities is employed or is a general partner or principal or in a similar position or in which such person or entity has a five percent (5%) or greater beneficial interest. Immediate family members includes a person’s spouse, parents, stepparents, children, stepchildren, siblings, mothers- and fathers-in-law, sons- and daughters-in-law, brothers- and sisters-in-law and anyone residing in such person’s home, other than a tenant or employee.
Transaction prices with our related parties are commensurate with transaction prices in arms-length transactions. For further details about our transactions with Related Parties, see Note (19) Related Party Transactions of Part II, “Item 8. Financial Statements and Supplementary Data.”
Recently Issued Accounting Standards
For discussion on the impact of accounting standards issued but not yet adopted to our consolidated financial statements, see Note (22) New Accounting Pronouncements of Part II, “Item 8. Financial Statements and Supplementary Data.”
Critical Accounting Estimates
The preparation of our consolidated financial statements and related notes included within Part II, “Item 8. Financial Statements and Supplementary Data” requires us to make estimates that affect the reported amounts of assets, liabilities, revenue and expenses and related disclosures of contingent assets and liabilities. We base these estimates on historical results and various other assumptions believed to be reasonable, all of which form the basis
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for making estimates concerning the carrying values of assets and liabilities that are not readily available from other sources. Actual results may differ from these estimates.
A critical accounting estimate is one that requires a high level of subjective judgment by management and has a material impact to our financial condition or results of operations. We believe the following are the critical accounting policies used in the preparation of our consolidated financial statements, as well as the significant estimates and judgments affecting the application of these policies. This discussion and analysis should be read in conjunction with our consolidated financial statements and related notes included within Part II, “Item 8. Financial Statements and Supplementary Data.”
Business combinations
We allocate the purchase price of businesses we acquire to the identifiable assets acquired and liabilities assumed based on their estimated fair values. Any excess purchase price over the fair value of the net identifiable assets acquired is recorded as goodwill. We use all available information to estimate fair values, including quoted market prices, the carrying value of acquired assets and assumed liabilities and valuation techniques such as discounted cash flows, multi-period excess earning or income-based-relief-from-royalty methods. We engage third-party appraisal firms to assist in the fair value determination of inventories, identifiable long-lived assets, identifiable intangible assets, as well as any contingent consideration or earn-out provisions that provide for additional consideration to be paid to the seller if certain future conditions are met. These estimates are reviewed during the 12-month measurement period and adjusted based on actual results. The judgments made in determining the estimated fair value assigned to each class of assets acquired and liabilities assumed, as well as asset lives, can materially impact our financial condition or results of operations. See Note (3) Mergers and Acquisitions of Part II, “Item 8. Financial Statements and Supplementary Data” for further discussion of our recently completed merger and acquisitions during 2019 and 2021.
Asset acquisitions
Asset acquisitions are measured based on their cost to us, including transaction costs incurred by us. An asset acquisition’s cost or the consideration transferred by us is assumed to be equal to the fair value of the net assets acquired. If the consideration transferred is cash, measurement is based on the amount of cash we paid to the seller, as well as transaction costs incurred by us. Consideration given in the form of nonmonetary assets, liabilities incurred or equity interests issued is measured based on either the cost to us or the fair value of the assets or net assets acquired, whichever is more clearly evident. The cost of an asset acquisition is allocated to the assets acquired based on their estimated relative fair values. We engage third-party appraisal firms to assist in the fair value determination of inventories, identifiable long-lived assets and identifiable intangible assets. Goodwill is not recognized in an asset acquisition.
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Legal and environmental contingencies
From time to time, we are subject to legal and administrative proceedings, settlements, investigations, claims and actions, as is typical of the industry. These claims include, but are not limited to, contract claims, environmental claims, employment related claims, claims alleging injury or claims related to operational issues. Our assessment of the likely outcome of litigation matters is based on our judgment of a number of factors, including experience with similar matters, past history, precedents, relevant financial information and other evidence and facts specific to the matter. We accrue for contingencies when the occurrence of a material loss is probable and can be reasonably estimated, based on our best estimate of the expected liability. The estimate of probable costs related to a contingency is developed in consultation with internal and outside legal counsel representing us. The accuracy of these estimates is impacted by, among other things, the complexity of the issues and the amount of due diligence we have been able to perform. Differences between the actual settlement costs, final judgments or fines from our estimates could have a material adverse effect on our financial position or results of operations. See Note (18) Commitments and Contingencies of Part II, “Item 8. Financial Statements and Supplementary Data” for further discussion of our legal, environmental and other regulatory contingencies.
Valuation of long-lived assets, indefinite-lived assets and goodwill
We assess our long-lived assets, including definite-lived intangible assets and property and equipment, for impairment whenever events or changes in circumstances indicate that the carrying amount of a long-lived asset may not be recoverable. We assess our goodwill and indefinite-lived assets for impairment annually, as of October 31, or whenever events or circumstances indicate that the carrying amount of goodwill or the indefinite-lived assets may not be recoverable. If the carrying value of an asset exceeds its fair value, we record an impairment charge that reduces our earnings.
We perform our qualitative assessments of the likelihood of impairment by considering qualitative factors relevant to each of our reporting units or asset groups, such as macroeconomic, industry, market or any other factors that have a significant bearing on fair value. The expected future cash flows used for impairment reviews and related fair value calculations are based on subjective, judgmental assessments of projected revenue growth, unit count, utilization, pricing, gross profit rates, SG&A rates, working capital fluctuations, capital expenditures, discount rates and terminal growth rates. Many of these judgments are driven by crude oil prices. If the crude oil market declines and remains at low levels for a sustained period of time, we would expect to perform our impairment assessments more frequently and could record impairment charges.
See Note (2)(f) Long-Lived Assets with Definite Lives and (2)(h) Goodwill and Indefinite-Lived Intangible Assets of Part II, “Item 8. Financial Statements and Supplementary Data” for further discussion on our impairment assessments of our long-lived assets, indefinite-lived assets and goodwill for the years ended December 31, 2021, 2020 and 2019.
Income Taxes
We account for income taxes in accordance with Accounting Standards Codification (“ASC”) 740, “Income Taxes,” which requires an asset and liability approach for financial accounting and reporting of income taxes. Under ASC 740, income taxes are accounted for based upon the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss carry-forwards using enacted tax rates in effect in the year the differences are expected to reverse. We estimate our annual effective tax rate at each interim period based on the facts and circumstances available at that time, while the actual effective tax rate is calculated at year-end. Our effective tax rates will vary due to changes in estimates of our future taxable income or losses, fluctuations in the tax jurisdictions in which we operate and favorable or unfavorable adjustments to our estimated tax liabilities related to proposed or probable assessments. As a result, our effective tax rate may fluctuate significantly on a quarterly or annual basis.
In evaluating our ability to recover our deferred tax assets, we consider all available positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning
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strategies and recent financial operations. In addition to our historical financial results, we consider forecasted market growth, earnings and taxable income, the mix of earnings in the jurisdictions in which we operate and the implementation of prudent and feasible tax planning strategies. These assumptions require significant judgment about the forecasts of future taxable income and are consistent with the plans and estimates we use to manage our underlying businesses. We establish a valuation allowance against the carrying value of deferred tax assets when we determine that it is more likely than not that the asset will not be realized through future taxable income. Such amounts are charged to earnings in the period in which we make such determination. Likewise, if we later determine that it is more likely than not that the net deferred tax assets would be realized, we would reverse the applicable portion of the previously provided valuation allowance.
We calculate our income tax liability based on estimates and assumptions that could differ from the actual results reflected in income tax returns filed during the subsequent year. Significant judgment is required in assessing, among other things, the timing and amounts of deductible and taxable items. Due to the complexity of some of these uncertainties, the ultimate resolution may result in payment that is materially different from our current estimate of our tax liabilities. These differences are reflected as increases or decreases to income tax expense in the period in which they are determined.
The amount of income tax we pay is subject to ongoing audits by federal and state tax authorities, which may result in proposed assessments. Our estimate for the potential outcome for any uncertain tax issue is highly judgmental. We believe we have adequately provided for any reasonably foreseeable outcome related to these matters. However, our future results may include favorable or unfavorable adjustments to our estimated tax liabilities in the period the assessments are made or resolved or when statutes of limitation on potential assessments expire. Additionally, the jurisdictions in which our earnings or deductions are realized may differ from our current estimates. We recognize interest and penalties, if any, related to uncertain tax positions in income tax expense.
See Note (17) Income Taxes of Part II, “Item 8. Financial Statements and Supplementary Data” for further discussion on income taxes for the years ended December 31, 2021, 2020 and 2019.
Leases
Per ASU 2016-02, "Leases (Topic 842)," lessees can classify leases as finance leases or operating leases, while lessors can classify leases as sales-type, direct financing or operating leases. All leases, with the exception of short-term leases, are capitalized on the balance sheet by recording a lease liability, which represents our obligation to make lease payments arising from the lease, along with a corresponding right-of-use asset, which represents our right to use the underlying asset being leased. For leases in which we are the lessee, we use a collateralized incremental borrowing rate to calculate the lease liability, as in most cases we do not know the lessor's implicit rate in the lease. Establishing our lease obligations on our consolidated balance sheets require judgmental assessments of the term lengths of each and the interest rate yield curve that best represents the collateralized incremental borrowing rate to apply to each lease. We engage third-party specialists to assist us in determining the collateralized incremental borrowing rate yield curve. Errors in determining the lease term lengths and/or selecting the best representative collateralized incremental borrowing rate can have a material adverse effect on our consolidated financial statements. For further details about our leases, see Note (16) Leases of Part II, “Item 8. Financial Statements and Supplementary Data”.
New Accounting Pronouncements
For discussion on the potential impact of new accounting pronouncements issued but not yet adopted, see Note (22) New Accounting Pronouncements of Part II, “Item 8. Financial Statements and Supplementary Data.”
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Item 7A. Quantitative and Qualitative Disclosure About Market Risk
Exchange Rate Risk. Our operations are currently conducted predominantly within the U.S.; therefore, we had no significant exposure to foreign currency exchange rate risk during 2021.
Interest Rate Risk. As of December 31, 2021, we held variable-rate debt, the exposure to which we manage with our interest-rate-related derivative instruments. We held no derivative instruments that increased our exposure to market risks for foreign currency rates, commodity prices or other market price risks. We are exposed to changes in interest rates on our floating rate borrowings under our 2019 ABL Facility and 2018 Term Loan. As of December 31, 2021, we had no debt outstanding under our 2019 ABL Facility and $337.8 million aggregate principal amount outstanding under the 2018 Term Loan. The impact of a 1.0% increase in interest rates under the terms of the 2019 ABL Facility would have no impact on interest expense for the 2021 year, and a 1.0% increase in interest rates under the terms of the 2018 Term Loan would have a $3.5 million impact on interest expense for the 2021 year.
Commodity Price Risk. Our material and fuel purchases expose us to commodity price risk. Our material costs primarily include the cost of inventory consumed while performing our stimulation services such as proppant and chemicals. Our fuel costs consist primarily of diesel fuel used by our various trucks and other motorized equipment. The prices for fuel and the raw materials (proppant and chemicals) in our inventory are volatile and are impacted by changes in supply and demand, as well as market uncertainty and regional shortages. Depending on market conditions, we have generally been able to pass along price increases to our customers; however, we may be unable to do so in the future. We generally do not engage in commodity price hedging activities. However, we have purchase commitments with certain vendors to supply a majority of the proppant used in our operations. Some of these agreements are take-or-pay agreements with minimum purchase obligations. As a result of future decreases in the market price of proppants, we could be required to purchase goods and pay prices in excess of market prices at the time of purchase.
For further quantitative disclosure about our market risk related to our variable-rate debt, interest-rate-related derivative instrument and purchase commitments, see Part II, “Item 7. Management Discussion and Analysis of Financial Condition and Results of Operations” for the contractual commitments and obligations table as of December 31, 2021 and Part II, “Item 8. Financial Statements and Supplementary Data” in Note (2)(i) Derivative Instruments and Hedging Activities and Note (10) Derivatives.
Customer Credit Risk. Financial instruments that potentially subject us to concentrations of credit risk are trade receivables. We extend credit to customers and other parties in the normal course of business. We have established various procedures to manage our credit exposure, including credit evaluations and maintaining an allowance for credit losses.
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Item 8. Financial Statements and Supplementary Data
INDEX TO FINANCIAL STATEMENTS
NexTier Oilfield Solutions Inc. | |||||
| Audited Consolidated Financial Statements | |||||
Reports of Independent Registered Public Accounting Firm | |||||
Consolidated Balance Sheets | |||||
| Consolidated Statements of Operations and Comprehensive Loss | |||||
| Consolidated Statements of Changes in Stockholders’ Equity | |||||
| Consolidated Statements of Cash Flows | |||||
| Notes to Consolidated Financial Statements | |||||
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Report of Independent Registered Public Accounting Firm
To the Stockholders and Board of Directors
NexTier Oilfield Solutions Inc.:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of NexTier Oilfield Solutions Inc. and subsidiaries (the Company) as of December 31, 2021 and 2020, the related consolidated statements of operations and comprehensive loss, changes in stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2021, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements 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 years in the three-year period ended December 31, 2021, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), 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, and our report dated February 23, 2022 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the 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 audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits 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. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Acquisition-date fair value of customer relationship intangible assets
As discussed in Note 3 to the consolidated financial statements, on August 31, 2021, the Company completed the acquisition of Alamo Pressure Pumping, LLC and its wholly owned subsidiaries. The
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Company accounted for the acquisition using the acquisition method of accounting. As a result of the transaction, the Company recorded $23.0 million for the fair value of acquired customer relationship intangible assets associated with the generation of future earnings from the acquirees existing customers, as of the acquisition date. The fair value of the customer relationship intangible assets was determined by the Company using a discounted cash flow model.
We identified the evaluation of the acquisition-date fair value of acquired customer relationship intangible assets as a critical audit matter. A high degree of subjective auditor judgment was required in evaluating the key assumptions used in the discounted cash flow model used to estimate the acquisition-date fair value, including forecasted revenue attributable to the customer relationships, gross profits rates, capital expenditures, and the discount rate. A change to those assumptions could have had a significant impact on the fair value of the customer relationships.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s acquisition-date fair value determination of the customer relationship intangible assets, including controls over the development of the key assumptions of forecasted revenue attributable to the customer relationships, gross profits rates, and capital expenditures and the discount rate. We evaluated the forecasted revenue attributable to the customer relationships, gross profit rates, and capital expenditures by comparing to the acquired entities’ actual historical results and by comparing to peer companies’ analyst estimates, historical financial information, and relevant industry data. We assessed the Company’s ability to accurately estimate forecasted revenues, gross profit rates and capital expenditures by comparing the forecasted amounts to the acquired entities’ actual results subsequent to the acquisition. In addition, we involved valuation professionals with specialized skills and knowledge who assisted in evaluating the discount rate by comparing it against a discount rate that was independently developed using publicly available market data for comparable entities.
Evaluation of long-lived assets for impairment triggering events
As discussed in Note 2(f) to the consolidated financial statements, the Company evaluates property and equipment and definite-lived intangible assets (collectively, long-lived assets) on a quarterly basis to identify events or changes in circumstances, referred to as triggering events, that indicate the carrying value of a long-lived asset may not be recoverable or upon the occurrence of a triggering event. An impairment loss is recorded in the period in which it is determined that the carrying amount of a long-lived asset is not recoverable. As of December 31, 2021, the carrying value of property and equipment, net and definite-lived intangible assets, net was $620.9 million and $65.0 million, respectively.
We identified the evaluation of long-lived assets for impairment triggering events as a critical audit matter. A high degree of subjective auditor judgment was required in evaluating the Company’s assessment of current operations, financial results and historical projections, current industry and market conditions, and relevant industry data for impairment indicators.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the Company’s process of identifying and assessing potential triggering events, including controls over the Company’s assessment of current operations, financial results and historical projections, current industry and market conditions, and relevant industry data. We evaluated the Company’s identification and assessment of triggering events by evaluating current period operations, financial results and historical projections, including consideration of current industry and market considerations. We compared relevant industry data used by the Company to external sources, including market index data and peer data. We evaluated the Company’s analysis over the factors and considered whether the Company omitted any significant internal or external elements in its evaluation.
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/s/ KPMG LLP
We have served as the Company’s auditor since 2011.
Houston, Texas
February 23, 2022
71
Report of Independent Registered Public Accounting Firm
To the Stockholders and Board of Directors
NexTier Oilfield Solutions Inc.:
Opinion on Internal Control Over Financial Reporting
We have audited NexTier Oilfield Solutions Inc. and subsidiaries' (the Company) 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. 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 Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2021 and 2020, the related consolidated statements of operations and comprehensive loss, changes in stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2021, and the related notes (collectively, the consolidated financial statements), and our report dated February 23, 2022 expressed an unqualified opinion on those consolidated financial statements.
The Company acquired Alamo Pressure Pumping, LLC during 2021, and management excluded from its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2021, Alamo Pressure Pumping, LLC’s internal control over financial reporting associated with total assets of $413.6 million and total revenues of $172.1 million included in the consolidated financial statements of the Company as of and for the year ended December 31, 2021. Our audit of internal control over financial reporting of the Company also excluded an evaluation of the internal control over financial reporting of Alamo Pressure Pumping, LLC.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the 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 audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. 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 audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
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 (1) pertain to the maintenance of records that, in reasonable detail,
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accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) 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 (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ KPMG LLP
Houston, Texas
February 23, 2022
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NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES
Consolidated Balance Sheets
(Amounts in thousands)
| December 31, 2021 | December 31, 2020 | |||||||||||||
| Assets | ||||||||||||||
| Current assets: | ||||||||||||||
Cash and cash equivalents | $ | 110,695 | $ | 275,990 | ||||||||||
Trade and other accounts receivable, net | 301,740 | 122,584 | ||||||||||||
Inventories, net | 38,094 | 30,068 | ||||||||||||
Assets held for sale | 1,555 | 126 | ||||||||||||
Prepaid and other current assets | 55,625 | 58,011 | ||||||||||||
Total current assets | 507,709 | 486,779 | ||||||||||||
Operating lease right-of-use assets | 21,767 | 37,157 | ||||||||||||
Finance lease right-of-use assets | 41,537 | 1,132 | ||||||||||||
| Property and equipment, net | 620,865 | 470,711 | ||||||||||||
Goodwill | 192,780 | 104,198 | ||||||||||||
| Intangible assets | 64,961 | 51,182 | ||||||||||||
Other noncurrent assets | 7,962 | 6,729 | ||||||||||||
Total assets | $ | 1,457,581 | $ | 1,157,888 | ||||||||||
| Liabilities and Stockholders’ Equity | ||||||||||||||
Liabilities | ||||||||||||||
Current liabilities: | ||||||||||||||
Accounts payable | $ | 190,963 | $ | 61,259 | ||||||||||
Accrued expenses | 213,923 | 134,230 | ||||||||||||
| Customer contract liabilities | 23,729 | 266 | ||||||||||||
Current maturities of long-term operating lease liabilities | 7,452 | 18,551 | ||||||||||||
Current maturities of long-term finance lease liabilities | 11,906 | 606 | ||||||||||||
Current maturities of long-term debt | 13,384 | 2,252 | ||||||||||||
Other current liabilities | 10,346 | 2,993 | ||||||||||||
Total current liabilities | 471,703 | 220,157 | ||||||||||||
Long-term operating lease liabilities, less current maturities | 20,446 | 24,232 | ||||||||||||
Long-term finance lease liabilities, less current maturities | 26,873 | 504 | ||||||||||||
Long-term debt, net of deferred financing costs and debt discount, less current maturities | 361,501 | 333,288 | ||||||||||||
Other noncurrent liabilities | 30,041 | 22,419 | ||||||||||||
Total noncurrent liabilities | 438,861 | 380,443 | ||||||||||||
Total liabilities | 910,564 | 600,600 | ||||||||||||
| Stockholders’ equity | ||||||||||||||
Common stock, par value $0.01 per share (authorized 500,000 shares, issued and outstanding 242,019 and 214,440 shares, respectively) | 2,420 | 2,144 | ||||||||||||
Paid-in capital in excess of par value | 1,094,020 | 989,995 | ||||||||||||
| Retained deficit | (541,164) | (421,741) | ||||||||||||
Accumulated other comprehensive loss | (8,259) | (13,110) | ||||||||||||
Total stockholders’ equity | 547,017 | 557,288 | ||||||||||||
Total liabilities and stockholders’ equity | $ | 1,457,581 | $ | 1,157,888 | ||||||||||
See accompanying notes to the consolidated financial statements.
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NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES
Consolidated Statements of Operations and Comprehensive Loss
(Amounts in thousands, except for per share amounts)
| Year Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| Revenue | $ | 1,423,441 | $ | 1,202,581 | $ | 1,821,556 | ||||||||||||||
| Operating costs and expenses: | ||||||||||||||||||||
Cost of services (1) | 1,255,321 | 1,032,574 | 1,403,932 | |||||||||||||||||
| Depreciation and amortization | 184,164 | 302,051 | 292,150 | |||||||||||||||||
| Selling, general and administrative expenses | 109,404 | 144,147 | 123,676 | |||||||||||||||||
| Merger and integration | 8,709 | 32,539 | 68,731 | |||||||||||||||||
| (Gain) loss on disposal of assets | (28,898) | (14,461) | 4,470 | |||||||||||||||||
| Impairment expense | — | 37,008 | 12,346 | |||||||||||||||||
Total operating costs and expenses | 1,528,700 | 1,533,858 | 1,905,305 | |||||||||||||||||
| Operating loss | (105,259) | (331,277) | (83,749) | |||||||||||||||||
| Other expense: | ||||||||||||||||||||
| Other income, net | 12,131 | 6,516 | 453 | |||||||||||||||||
| Interest expense | (24,609) | (20,652) | (21,856) | |||||||||||||||||
Total other expenses | (12,478) | (14,136) | (21,403) | |||||||||||||||||
| Loss before income taxes | (117,737) | (345,413) | (105,152) | |||||||||||||||||
| Income tax expense | (1,686) | (1,470) | (1,005) | |||||||||||||||||
| Net Loss | (119,423) | (346,883) | (106,157) | |||||||||||||||||
| Other comprehensive loss, net of tax: | ||||||||||||||||||||
| Foreign currency translation adjustments | 407 | (241) | (116) | |||||||||||||||||
| Hedging activities | 1,703 | (6,422) | (7,628) | |||||||||||||||||
| Total comprehensive loss | $ | (117,313) | $ | (353,546) | $ | (113,901) | ||||||||||||||
| Net loss per share: | ||||||||||||||||||||
| Basic net loss per share | $ | (0.53) | $ | (1.62) | $ | (0.86) | ||||||||||||||
| Diluted net loss per share | $ | (0.53) | $ | (1.62) | $ | (0.86) | ||||||||||||||
| Weighted-average shares outstanding: basic | 224,401 | 213,795 | 122,977 | |||||||||||||||||
| Weighted-average shares outstanding: diluted | 224,401 | 213,795 | 122,977 | |||||||||||||||||
(1) Cost of services during the years ended December 31, 2021, 2020, and 2019 excludes depreciation of $166.4 million, $283.8 million, and $276.8 million, respectively. Depreciation related to cost of services is presented within depreciation and amortization separately.
See accompanying notes to the consolidated financial statements.
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NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES
Consolidated Statements of Changes in Stockholders’ Equity
(Amounts in thousands)
| Common Stock | Paid-in Capital in Excess of Par Value | Retained Earnings (deficit) | Accumulated other comprehensive income (loss) | Total | ||||||||||||||||||||||||||||
| Balance as of December 31, 2018 | $ | 1,038 | $ | 455,447 | $ | 31,494 | $ | (798) | $ | 487,181 | ||||||||||||||||||||||
| New lease standard implementation | — | — | 1,330 | — | 1,330 | |||||||||||||||||||||||||||
Stock-based compensation(1) | 33 | 33,226 | — | — | 33,259 | |||||||||||||||||||||||||||
| Shares repurchased and retired related to stock-based compensation | (6) | (5,976) | — | — | (5,982) | |||||||||||||||||||||||||||
| Other comprehensive loss | — | — | — | (7,983) | (7,983) | |||||||||||||||||||||||||||
| Equity issued in connection with the C&J Merger | 1,059 | 484,065 | — | — | 485,124 | |||||||||||||||||||||||||||
| Net loss | — | — | (106,157) | — | (106,157) | |||||||||||||||||||||||||||
| Balance as of December 31, 2019 | $ | 2,124 | $ | 966,762 | $ | (73,333) | $ | (8,781) | $ | 886,772 | ||||||||||||||||||||||
| — | — | (1,525) | — | (1,525) | ||||||||||||||||||||||||||||
Stock-based compensation(1) | 27 | 25,799 | — | — | 25,826 | |||||||||||||||||||||||||||
| Shares repurchased and retired related to stock-based compensation | (7) | (2,566) | — | — | (2,573) | |||||||||||||||||||||||||||
| Other comprehensive loss | — | — | — | (4,329) | (4,329) | |||||||||||||||||||||||||||
| Net loss | — | — | (346,883) | — | (346,883) | |||||||||||||||||||||||||||
| Balance as of December 31, 2020 | $ | 2,144 | $ | 989,995 | $ | (421,741) | $ | (13,110) | $ | 557,288 | ||||||||||||||||||||||
| Stock-based compensation | 19 | 24,658 | — | — | 24,677 | |||||||||||||||||||||||||||
| Shares repurchased and retired related to stock-based compensation | (3) | (2,696) | — | — | (2,699) | |||||||||||||||||||||||||||
| Equity issued in connection with Alamo Acquisition | 260 | 82,063 | — | — | 82,323 | |||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | 4,851 | 4,851 | |||||||||||||||||||||||||||
| Net loss | — | — | (119,423) | — | (119,423) | |||||||||||||||||||||||||||
| Balance as of December 31, 2021 | $ | 2,420 | $ | 1,094,020 | $ | (541,164) | $ | (8,259) | 547,017 | |||||||||||||||||||||||
(1) Stock-based compensation during 2019 includes stock-based compensation expense recognized during the period of $29.0 million and the vested deferred stock awards of $4.3 million. Refer to Note (12) Stock-Based Compensation for further discussion of the Company’s stock-based compensation.
See accompanying notes to the consolidated financial statements.
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Consolidated Statements of Cash Flows
(Amounts in thousands)
| Year Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| Cash flows from operating activities: | ||||||||||||||||||||
| Net loss | $ | (119,423) | $ | (346,883) | $ | (106,157) | ||||||||||||||
| Adjustments to reconcile net loss to net cash provided by (used in) operating activities | ||||||||||||||||||||
| Depreciation and amortization | 184,164 | 302,051 | 292,150 | |||||||||||||||||
| Amortization of deferred financing fees | 2,066 | 2,217 | 1,360 | |||||||||||||||||
| (Gain) loss on disposal of assets | (28,898) | (14,461) | 4,470 | |||||||||||||||||
| Stock-based compensation | 24,677 | 25,826 | 28,977 | |||||||||||||||||
| Loss on debt extinguishment/modification, including prepayment premiums | — | — | 526 | |||||||||||||||||
| Unrealized gain (loss) on derivative recognized in other comprehensive loss | 1,703 | (6,422) | (7,628) | |||||||||||||||||
| (Gain) loss on financial instrument and derivatives, net | 1,799 | (2,815) | (239) | |||||||||||||||||
| Gain on insurance proceeds recognized in other income | (10,409) | — | — | |||||||||||||||||
| Loss on impairment of assets | — | 37,008 | 12,346 | |||||||||||||||||
| Changes in operating assets and liabilities | ||||||||||||||||||||
| Decrease (increase) in trade and other accounts receivable, net | (128,535) | 183,083 | 172,566 | |||||||||||||||||
| Decrease (increase) in inventories | (9,978) | 19,167 | 17,181 | |||||||||||||||||
| Decrease (increase) in prepaid and other current assets | (10,894) | 5,160 | 3,703 | |||||||||||||||||
| Decrease (increase) in other assets | 24,807 | 25,306 | (242) | |||||||||||||||||
| Increase (decrease) in accounts payable | 18,693 | (61,658) | (17,799) | |||||||||||||||||
| Increase (decrease) in customer contract liabilities | (6,537) | 206 | — | |||||||||||||||||
| Increase (decrease) in accrued expenses | 34,860 | (84,129) | (103,609) | |||||||||||||||||
| Increase (decrease) in other liabilities | (28,882) | (14,771) | 7,858 | |||||||||||||||||
| Net cash provided by (used in) operating activities | (50,787) | 68,885 | 305,463 | |||||||||||||||||
| Cash flows from investing activities | ||||||||||||||||||||
| Business acquisitions, including cash received | (95,082) | 53,666 | 68,807 | |||||||||||||||||
| Purchase of property and equipment | (184,496) | (113,506) | (200,385) | |||||||||||||||||
| Advances of deposit on equipment | (961) | (1,908) | (7,451) | |||||||||||||||||
| Implementation of software | (3,021) | (8,813) | (4,408) | |||||||||||||||||
| Proceeds from sale of assets | 70,432 | 32,659 | 29,114 | |||||||||||||||||
| Proceeds from insurance recoveries | 22,947 | 58 | 223 | |||||||||||||||||
| Proceeds from settlement of WSS Notes and make-whole derivative | 34,350 | — | — | |||||||||||||||||
| Payment of consideration liability | (7,370) | — | — | |||||||||||||||||
| Net cash used in investing activities | (163,201) | (37,844) | (114,100) | |||||||||||||||||
| Cash flows from financing activities: | ||||||||||||||||||||
| Proceeds from the asset-based revolver and equipment loan | 43,329 | 175,000 | — | |||||||||||||||||
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NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES
Consolidated Statements of Cash Flows
(Amounts in thousands)
| Payments on the asset-based revolver, term loan facilities, and equipment loan | (4,976) | (178,500) | (3,500) | |||||||||||||||||
| Payments on finance leases | (4,155) | (3,752) | (6,035) | |||||||||||||||||
| Payment of debt issuance costs | (277) | — | (1,229) | |||||||||||||||||
| Proceeds from financing liabilities | 17,759 | — | — | |||||||||||||||||
| Payments for financing liabilities | (695) | — | — | |||||||||||||||||
| Shares repurchased and retired related to stock-based compensation | (2,699) | (2,573) | (5,982) | |||||||||||||||||
| Net cash provided by (used in) financing activities | 48,286 | (9,825) | (16,746) | |||||||||||||||||
| Non-cash effect of foreign translation adjustments | 407 | (241) | 192 | |||||||||||||||||
| Net increase (decrease) in cash, cash equivalents and restricted cash | (165,295) | 20,975 | 174,809 | |||||||||||||||||
| Cash, cash equivalents and restricted cash, beginning | 275,990 | 255,015 | 80,206 | |||||||||||||||||
| Cash, cash equivalents and restricted cash, ending | $ | 110,695 | $ | 275,990 | $ | 255,015 | ||||||||||||||
| Supplemental disclosure of cash flow information: | ||||||||||||||||||||
| Cash paid during the period for: | ||||||||||||||||||||
| Interest expense, net | $ | 23,242 | $ | 21,114 | $ | 20,836 | ||||||||||||||
| Income taxes | 217 | 1,206 | 1,726 | |||||||||||||||||
| Non-cash investing and financing activities: | ||||||||||||||||||||
| Change in accrued capital expenditures | $ | (71,897) | $ | (13,812) | $ | (17,274) | ||||||||||||||
| Non-cash additions to equity security investment | — | 5,263 | — | |||||||||||||||||
| Non-cash additions to finance right-of use assets | 42,592 | — | 6,269 | |||||||||||||||||
| Non-cash additions to finance lease liabilities, including current maturities | (42,592) | — | (6,286) | |||||||||||||||||
| Non-cash additions to operating right-of-use assets | 9,047 | 9,057 | 65,551 | |||||||||||||||||
| Non-cash additions to operating lease liabilities, including current maturities | (7,416) | (8,898) | (65,297) | |||||||||||||||||
| Fair value of C&J assets acquired | — | — | 806,218 | |||||||||||||||||
106,627 shares of NexTier common stock issued in exchange for C&J capital stock and replacement awards | — | — | (485,124) | |||||||||||||||||
| C&J liabilities assumed | — | — | (321,094) | |||||||||||||||||
26,000,000 shares of NexTier common stock issued in exchange for Alamo ownership | (82,323) | — | — | |||||||||||||||||
| Total contingent consideration | (45,944) | — | — | |||||||||||||||||
| Non contingent consideration | (7,370) | — | — | |||||||||||||||||
See accompanying notes to the consolidated financial statements.
78
(1) Basis of Presentation and Nature of Operations
The accompanying consolidated financial statements were prepared using United States (“U.S.”) Generally Accepted Accounting Principles (“GAAP”) and the instructions to Form 10-K and Regulation S-X and include all of the accounts of NexTier and its consolidated subsidiaries. All intercompany transactions and balances have been eliminated.
The Company’s accounting policies are in accordance with GAAP. The preparation of financial statements in conformity with these accounting principles requires the Company to make estimates and assumptions that affect (1) the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and (2) the reported amounts of revenue and expenses during the reporting period. Ultimate results could differ from the Company’s estimates. Significant items subject to such estimates and assumptions include the useful lives of property and equipment and intangible assets; allowances for doubtful accounts; inventory reserves; acquisition accounting; contingent liabilities; and the valuation of property and equipment, intangible assets, equity issued as consideration in an acquisition, income taxes, stock-based incentive plan awards and derivatives.
Management believes the consolidated financial statements included herein contain all adjustments necessary to present fairly the Company’s financial position as of December 31, 2021 and 2020 and the results of its operations and cash flows for the years ended December 31, 2021, 2020 and 2019. Such adjustments are of a normal recurring nature.
On October 31, 2019, the Company completed its merger (the “C&J Merger”) with C&J Energy Services, Inc. (“C&J”) and changed its name to "NexTier Oilfield Solutions Inc." For more details regarding the C&J Merger, refer to Note (3) Mergers and Acquisitions.
The consolidated financial statements for the period from January 1, 2019 to October 31, 2019 reflect only the historical results of the Company prior to the completion of the C&J Merger. The financial statements have been prepared using the acquisition method of accounting under existing U.S. GAAP, which requires that one of the two companies in the C&J Merger be designated as the acquirer for accounting purposes. C&J and Keane determined that Keane was the accounting acquirer. Accordingly, consideration given by Keane to complete the C&J Merger was allocated to the underlying tangible and intangible assets and liabilities acquired based on their estimated fair values as of the date of completion of the C&J Merger, with any excess purchase price allocated to goodwill.
In addition, on March 9, 2020, the Company completed the divestiture of its Well Support Services Segment (“WSS Sale”). For more details regarding the WSS Sale, refer to Note (21) Business Segments.
On August 31, 2021 the Company completed its acquisition (“Alamo Acquisition”) of Alamo Pressure Pumping, LLC and its wholly owned subsidiaries (“Alamo”). For more details regarding the Alamo Acquisition, refer to Note (3) Mergers and Acquisitions.
The consolidated financial statements for the period from January 1, 2019 to August 31, 2021 reflect only the historical results of the Company prior to the completion of the Alamo Acquisition. The financial statements have been prepared using the acquisition method of accounting under existing U.S. GAAP, which requires that one of the two companies in the Alamo Acquisition be designated as the acquirer for accounting purposes. The Company and Alamo determined that the Company was the accounting acquirer. Accordingly, consideration given by the Company to complete the Alamo Acquisition was allocated to the underlying tangible and intangible assets and liabilities acquired based on their estimated fair values as of the date of completion of the Alamo Acquisition, with any excess purchase price allocated to goodwill.
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NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
(2) Summary of Significant Accounting Policies
(a) Business Combinations and Asset Acquisitions
Business combinations are accounted for using the acquisition method of accounting in accordance with the Accounting Standards Codification (“ASC”) 805, “Business Combinations”, as amended by Accounting Standards Update (“ASU”) 2017-01, “Business Combinations (Topic 805), Clarifying the Definition of a Business.” The purchase price is allocated to the assets acquired and liabilities assumed based on their estimated fair values. Fair value of the acquired assets and liabilities is measured in accordance with the guidance of ASC 820, using discounted cash flows and other applicable valuation techniques. Any acquisition related costs incurred by the Company are expensed as incurred. Any excess purchase price over the fair value of the net identifiable assets acquired is recorded as goodwill if the definition of a business is met. Operating results of an acquired business are included in the Company’s results of operations from the date of acquisition.
Asset acquisitions are measured based on their cost to the Company, including transaction costs. Asset acquisition costs, or the consideration transferred by the Company, are assumed to be equal to the fair value of the net assets acquired. If the consideration transferred is cash, measurement is based on the amount of cash the Company paid to the seller, as well as transaction costs incurred. Consideration given in the form of non-monetary assets, liabilities incurred or equity interests issued is measured based on either the cost to the Company or the fair value of the assets or net assets acquired, whichever is more clearly evident. The cost of an asset acquisition is allocated to the assets acquired based on their estimated relative fair values. Goodwill is not recognized in an asset acquisition.
Refer to Note (3) Mergers and Acquisitions for discussion of the mergers and acquisitions completed in 2021 and 2019.
(b) Cash and Cash Equivalents
The Company considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents. The Company’s cash is invested in overnight repurchase agreements and certificates of deposit with an initial term of less than three months.
Net cash received from certain dispositions or casualty events of more than $25.0 million per single transaction or $50.0 million per series of related transactions, under the 2018 Term Loan Facility (as defined herein), and of more than $50.0 million, under the 2019 ABL Facility (as defined herein), is not considered to be restricted as long as the Company, at management’s discretion, reinvests any part of such proceeds in assets (other than current assets) to be used for its business (in the case of the 2018 Term Loan Facility) and for replacing or repairing the assets in respect of which such proceeds were received (in the case of the 2019 ABL Facility), in each case within 12 months from the receipt date of such proceeds. Otherwise, the proceeds are required to be applied as a prepayment of the 2018 Term Loan Facility or any outstanding commitments under the 2019 ABL Facility. The Company did not have any qualifying asset sale proceeds or insurance proceeds that exceeded the dollar thresholds described above for the years ended December 31, 2021 and 2020.
The Company had less than $0.1 million of restricted cash as of December 31, 2021 and December 31, 2020, respectively.
(c) Trade Accounts Receivable
Trade accounts receivable are generally recorded at the invoiced amount. Amounts collected on trade accounts receivable are included in net cash provided by operating activities in the consolidated statements of cash flows. As a result of the adoption of ASU 2016-13 “Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments,” on January 1, 2020 the Company evaluates its accounts receivable through a continuous process of assessing its portfolio on an individual customer and overall basis. This process consists of a thorough review of historical collection experience, current aging status of the customer accounts, and financial condition of customers. Based on our review of these factors, we establish or adjust allowances for specific customers. Trade accounts receivable were $303.6 million and $125.3 million at December 31, 2021 and 2020,
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NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
respectively. As of December 31, 2021, and 2020, the Company had an allowance for credit losses of $1.9 million and $2.7 million, respectively.
(d) Inventories
Inventories are stated at the lower of cost or net realizable value. Costs of inventories include purchase, conversion and condition. As inventory is consumed, the expense is recorded in cost of services in the consolidated statements of operations and comprehensive loss using the weighted average cost method for non-manufacturing inventory and standard cost method for manufacturing inventory.
The Company periodically reviews the nature and quantities of inventory on hand and evaluates the net realizable value of items based on historical usage patterns, known changes to equipment or processes and customer demand for specific products. Significant or unanticipated changes in business conditions could impact the magnitude and timing of impairment recognized. Provision for excess or obsolete inventories is determined based on historical usage of inventory on-hand, volume on-hand versus anticipated usage, technological advances and consideration of current market conditions. Inventories that have not turned over for more than a year are subject to a slow-moving reserve provision. In addition, inventories that have become obsolete due to technological advances, excess volume on-hand or no longer configured to operate with the Company’s equipment are written-off.
(e) Revenue Recognition
Revenues are accounted for in accordance with ASU 2014-09, “Revenue from Contracts with Customers,” which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers.
The majority of the Company’s performance obligations are satisfied over time. The Company has determined this best represents the transfer of value from its services to the customer as performance by the Company helps to enhance a customer controlled asset (e.g., unplugging a well, enabling a well to produce oil or natural gas). Measurement of the satisfaction of the performance obligation is measured using the output method, which is typically evidenced by a field ticket. A field ticket includes items such as services performed, consumables used, and man hours incurred to complete the job for the customer. Each field ticket is used to invoice customers. Payment terms for invoices issued are in accordance with a master services agreement with each customer, which typically require payment within 30 to 60 days of the invoice issuance.
A portion of the Company’s contracts contain variable consideration; however, this variable consideration is typically unknown at the time of contract inception, and is not known until the job is complete, at which time the variability is resolved. Examples of variable consideration include the number of hours that will be incurred and the amount of consumables (such as chemicals and proppants) that will be used to complete a job.
Remaining Performance Obligations
The Company invoices its customers for the services provided at contractual rates multiplied by the applicable unit of measurement, including volume of consumables used and hours incurred. In accordance with Accounting Standards Codification 606 “Revenue from Contracts with Customers” (“ASC 606”), the Company has elected the “Right to Invoice” practical expedient for all contracts, which allows the Company to invoice its customers in an amount that corresponds directly with the value to the customer of the entity’s performance completed to date. With this election, the Company is not required to disclose information about the variable consideration related to its remaining performance obligations. The Company has also elected the practical expedient to expense immediately mobilization costs, as the amortization period would always be less than one year. For those contracts with a term of more than one year, the Company had approximately $27.0 million of unsatisfied performance obligations as of December 31, 2021, which will be recognized as services are performed over the remaining contractual terms.
The Company’s obligations for refunds as well as the warranties and related obligations stated in its contracts with its customers are standard to the industry and are related to the correction of any defectiveness in the execution of its performance obligations.
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NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Contract Balances
In line with industry practice, the Company bills its customers for its services in arrears, typically when the stage or well is completed or at month-end. The majority of the Company’s jobs are completed in less than 30 days. Furthermore, it is currently not standard practice for the Company to execute contracts with prepayment features. As of December 31, 2021, the Company’s customer contract liability balance is related to the post close service agreement as a result of the Alamo Acquisition. Payment terms after invoicing are typically 30 to 60 days or less.
The Company does not have any significant contract costs to obtain or fulfill contracts with customers; as such, no amounts are recognized on the consolidated balance sheet. Taxes collected from customers and remitted to governmental authorities are accounted for on a net basis and, therefore, are excluded from revenues in the consolidated statements of operations and comprehensive loss and net cash provided by operating activities in the consolidated statements of cash flows.
The following is a description of the Company’s core service lines separated by reportable segments from which the Company generates its revenue. For additional detailed information regarding reportable segments, see (21) Business Segments.
Revenue from the Company’s Completion Services, Well Construction and Intervention (“WC&I”), and Well Support Services segments are recognized as follows:
Completion Services
The Company provides hydraulic fracturing, wireline and pumpdown services pursuant to contractual arrangements, such as term contracts and pricing agreements. Revenue from these services are earned as services are rendered, which is generally on a per stage or fixed monthly rate. All revenue is recognized when a contract with a customer exists, the performance obligations under the contract have been satisfied over time, the amount to which the Company has the right to invoice has been determined and collectability of amounts subject to invoice is probable. Contract fulfillment costs, such as mobilization costs and shipping and handling costs, are expensed as incurred and are recorded in cost of services in the consolidated statements of operations and comprehensive loss. To the extent fulfillment costs are considered separate performance obligations that are billable to the customer, the amounts billed are recorded as revenue in the consolidated statements of operations and comprehensive loss.
Once a stage has been completed, a field ticket is created that includes charges for the service performed and the chemicals and proppant consumed during the course of the service. The field ticket may also include charges for the mobilization of the equipment to the location, any additional equipment used on the job and other miscellaneous items. The field ticket represents the amounts to which the Company has the right to invoice and to recognize as revenue.
Well Construction and Intervention
The Company provides cementing services pursuant to contractual arrangements, such as term contracts, or on a spot market basis. Revenue is recognized upon the completion of each performance obligation, which for cementing services, represents the portion of the well cemented: surface casing, intermediate casing or production liner. The performance obligations are satisfied over time. Jobs for these services are typically short term in nature, with most jobs completed in a day. Once the well has been cemented, a field ticket is created that includes charges for the services performed and the consumables used during the course of service. The field ticket represents the amounts to which the Company has the right to invoice and to recognize as revenue.
The Company provides a range of coiled tubing services primarily used for fracturing plug drill-out during completion operations and for well workover and maintenance, primarily on a spot market basis. Jobs for these services are typically short-term in nature, lasting anywhere from a few hours to multiple days. Revenue is recognized upon completion of each day’s work based upon a completed field ticket. The field ticket includes charges for the services performed and the consumables used during the course of service. The field ticket may also include charges for the mobilization and set-up of equipment, the personnel on the job, any additional equipment used on the job, and other miscellaneous consumables. The Company typically charges the customer for the services
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NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
performed and resources provided on an hourly basis at agreed-upon spot market rates, at times, or pursuant to pricing agreements.
Historical Segment: Well Support Services
On March 9, 2020, the Company completed the divestiture of its Well Support Services segment. For additional information, see Note (21) Business Segments. Through its rig services line, the Company had provided workover and well servicing rigs that were primarily used for routine repair and maintenance of oil and gas wells, re-drilling operations and plug and abandonment operations. These services were provided on an hourly basis at prices that approximate spot market rates. A field ticket was generated and revenue is recognized upon the earliest of the completion of a job or at the end of each day.
Through its fluids management service line, the Company used to provide storage, transportation and disposal services for fluids used in the drilling, completion and workover of oil and gas wells. Rates for these services vary and can be on a per job, per hour, or per load basis, or on the basis of quantities sold or disposed. Revenue is recognized upon the completion of each job or load, or delivered product, based on a completed field ticket.
Through its other special well site service line, the Company used to provide fishing, contract labor and tool rental services for completion and workover of oil and gas wells. Rates for these services vary and can be on a per job, per hour or on the basis of rental days per month. Revenue is recognized based on a field ticket issued upon the completion of each job or on a monthly billing for rental services provided.
Disaggregation of Revenue
Revenue activities during the years ended December 31, 2021, 2020 and 2019 were as follows:
| Year Ended December 31, 2021 | ||||||||||||||||||||||||||
| Completion Services | WC&I | Well Support Services | Total | |||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||
| Geography | ||||||||||||||||||||||||||
| Northeast | $ | 248,652 | $ | 21,881 | $ | — | $ | 270,533 | ||||||||||||||||||
| Central | 263,427 | — | — | 263,427 | ||||||||||||||||||||||
| West Texas | 680,716 | 72,565 | — | 753,281 | ||||||||||||||||||||||
| West | 95,072 | 4,107 | — | 99,179 | ||||||||||||||||||||||
| International | 37,021 | — | — | 37,021 | ||||||||||||||||||||||
| $ | 1,324,888 | $ | 98,553 | $ | — | $ | 1,423,441 | |||||||||||||||||||
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NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
| Year Ended December 31, 2020 | ||||||||||||||||||||||||||
| Completion Services | WC&I | Well Support Services | Total | |||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||
| Geography | ||||||||||||||||||||||||||
| Northeast | $ | 270,612 | $ | 21,290 | $ | — | $ | 291,902 | ||||||||||||||||||
| Central | 131,833 | 7,478 | — | 139,311 | ||||||||||||||||||||||
| West Texas | 477,758 | 58,111 | 8,373 | 544,242 | ||||||||||||||||||||||
| West | 122,970 | 11,459 | 49,556 | 183,985 | ||||||||||||||||||||||
| International | 43,141 | — | — | 43,141 | ||||||||||||||||||||||
| $ | 1,046,314 | $ | 98,338 | $ | 57,929 | $ | 1,202,581 | |||||||||||||||||||
| Year Ended December 31, 2019 | ||||||||||||||||||||||||||
| Completion Services | WC&I | Well Support Services | Total | |||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||
| Geography | ||||||||||||||||||||||||||
| Northeast | $ | 479,685 | $ | 5,193 | $ | — | $ | 484,878 | ||||||||||||||||||
| Central | 104,225 | 5,741 | — | 109,966 | ||||||||||||||||||||||
| West Texas | 839,652 | 24,575 | 9,336 | 873,563 | ||||||||||||||||||||||
| West | 273,364 | 27,530 | 39,247 | 340,141 | ||||||||||||||||||||||
| International | 13,008 | — | — | 13,008 | ||||||||||||||||||||||
| $ | 1,709,934 | $ | 63,039 | $ | 48,583 | $ | 1,821,556 | |||||||||||||||||||
(f) Long-Lived Assets with Definite Lives
Property and equipment, inclusive of equipment under finance lease, are generally stated at cost.
Depreciation on property and equipment is calculated using the straight-line method over the estimated useful lives of the assets, which range from 13 months to 40 years. Management bases the estimate of the useful lives and salvage values of property and equipment on expected utilization, technological change and effectiveness of its maintenance programs. Depreciation methods, useful lives and residual values are reviewed annually or as needed based on activities related to specific assets. When components of an item of property and equipment are identifiable and have different useful lives, they are accounted for separately as major components of property and equipment.
Gains and losses on disposal of property and equipment are determined by comparing the proceeds from disposal with the carrying amount of property and equipment and are recognized net within operating costs and expenses in the consolidated statements of operations and comprehensive loss.
Major classifications of property and equipment and their respective useful lives are as follows:
| Land | Indefinite life | ||||
| Building and leasehold improvements | 13 months – 40 years | ||||
| Machinery and equipment | 13 months – 10 years | ||||
| Office furniture, fixtures and equipment | 3 years – 5 years | ||||
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NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Leasehold improvements are assigned a useful life equal to the term of the related lease, or its expected period of use.
In the first quarter of 2021, the Company reassessed the estimated useful lives of select machinery and equipment, concluding that due to a decrease in service intensity for select machinery and equipment driven by operational parameters required to maximize natural gas substitution and longer major component lives attributable to equipment health monitoring and predictive maintenance from our proprietary digital NexHub platform and data science efforts, the useful lives of select machinery and equipment should be increased by 1-2 years depending on the specific asset class. In accordance with ASC 250, “Accounting Changes and Error Corrections” the change in the estimated useful lives of the Company’s property and equipment was accounted for as a change in accounting estimate, on a prospective basis, effective January 1, 2021. This change resulted in a decrease in depreciation expense and decrease in net loss during the twelve months ended December 31, 2021 of $30.6 million, in the consolidated statement of operations and comprehensive loss.
Amortization on definite-lived intangible assets is calculated on the straight-line method over the estimated useful lives of the assets, which range from 2 to 15 years.
Property and equipment and definite-lived intangible assets (“Long-lived Assets”) are evaluated on a quarterly basis to identify events or changes in circumstances, referred to as triggering events that indicate the carrying value of a Long-lived Asset may not be recoverable or upon the occurrence of a triggering event. An impairment loss is recorded in the period in which it is determined that the carrying amount of a Long-lived Asset is not recoverable. The determination of recoverability is made based upon the estimated undiscounted future net cash flows of assets grouped at the lowest level for which there are identifiable cash flows independent of the cash flows of other groups of assets with such cash flows to be realized over the estimated remaining useful life of the primary asset within the asset group. The Company determined the lowest level of identifiable cash flows that are independent of other asset groups to be primarily at the service line level. The Company's asset groups consist of fracturing services, wireline, cementing, and coiled tubing, except for an entity level asset group for Long-lived Assets that do not have identifiable independent cash flows. Estimates of undiscounted future net cash flows of assets groups are projected based on estimates of projected revenue growth, unit count, utilization, pricing, gross profit rates, SG&A rates, working capital fluctuations and capital expenditures. Forecasted cash flows take into account known market conditions as of the assessment date, and management’s anticipated business outlook. A terminal period is used to reflect an estimate of stable, perpetual growth. If the estimated undiscounted future net cash flows for a given asset group is less than the carrying amount of the asset groups, an impairment loss is determined by comparing the estimated fair value with the carrying value of the related asset groups. The impairment loss is then allocated across the asset group's major classifications.
During the first quarter of 2020, management determined the reductions in commodity prices driven by the potential impact of the novel COVID-19 pandemic and global supply and demand dynamics coupled with the sustained decrease in the Company’s share price were deemed triggering events. As a result of the triggering event, recoverability testing was performed and it was determined that the estimated undiscounted future net cash flow for all asset groups was greater than the carrying amount of their related assets and no impairment loss was recorded.
During the third quarter of 2020, the Company assessed and determined the sustained reductions in commodity prices and continuing market economic disruptions as a triggering event. As a result of the triggering event, recoverability testing was performed and it was determined that the estimated undiscounted future net cash flows for all asset groups was greater than the carrying amount of their related assets and no impairment loss was recorded.
The Company did not recognize any impairment charges related to the Company’s long-lived assets for the years ended December 31, 2021, 2020, or 2019.
(g) Major Maintenance Activities
The Company incurs maintenance costs on its major equipment. The determination of whether an expenditure should be capitalized or expensed requires management judgment in the application of how the costs
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Notes to the Consolidated Financial Statements
benefit future periods, relative to the Company’s capitalization policy. Costs that either establish or materially increase the efficiency, productivity, functionality or life of a fixed asset are capitalized.
(h) Goodwill and Indefinite-Lived Intangible Assets
Goodwill represents the excess of the purchase price of an acquired business over the estimated fair value of the identifiable assets acquired and liabilities assumed by the Company. For the purposes of goodwill impairment assessment, the Company evaluates goodwill for impairment annually, as of October 31, or more often as facts and circumstances warrant. When performing the impairment assessment, the Company evaluates factors, such as unexpected adverse economic conditions, competition and market changes. Goodwill is allocated across the Company’s Completions Services, Well Construction and Intervention and Well Support Services reporting units.
Before employing detailed impairment testing methodologies, the Company may first evaluate the likelihood of impairment by considering qualitative factors relevant to each reporting unit, such as macroeconomic, industry, market or any other factors that have a significant bearing on fair value. If the Company first utilizes a qualitative approach and determines that it is more likely than not that goodwill is impaired, detailed testing methodologies are then applied. Otherwise, the Company concludes that no impairment has occurred. The Company may also choose to bypass a qualitative approach and opt instead to employ detailed testing methodologies, regardless of a possible more likely than not outcome. The first step in the goodwill impairment test is to compare the fair value of each reporting unit to which goodwill has been assigned to the carrying amount of net assets, including goodwill, of the respective reporting unit. If the carrying amount of the reporting unit exceeds its fair value, the Company recognizes an impairment expense in an amount equal to the excess, limited to the total amount of goodwill allocated to the reporting unit.
The Company performs the qualitative analysis of the goodwill impairment assessment by reviewing relevant qualitative factors. In the first and third quarter of 2020, the Company determined there were triggering events that would indicate the carrying amount of its goodwill may not be recoverable, and as such, quantitative detail impairment testing was conducted.
As a result, the Company recognized $32.6 million in goodwill impairment expense during 2020, of which $32.2 million related to the Completions Service reporting unit and $0.4 million representing the entire goodwill balance for the Well Construction and Intervention reporting unit. No goodwill impairment expense was recognized in 2021 or 2019. See Note (5) Goodwill.
(i) Derivative Instruments and Hedging Activities
The Company utilizes interest rate derivatives to manage interest rate risk associated with its floating-rate borrowings. The Company recognizes all derivative instruments as either assets or liabilities on the consolidated balance sheets at their respective fair values. For derivatives designated in hedging relationships, changes in the fair value are either offset through earnings against the change in fair value of the hedged item attributable to the risk being hedged or recognized in accumulated other comprehensive loss until the hedged item affects earnings.
The Company only enters into derivative contracts that it intends to designate as hedges for the variability of cash flows to be received or paid related to a recognized asset or liability (i.e. cash flow hedge). For all hedging relationships, the Company formally documents the hedging relationship and its risk-management objective and strategy for undertaking the hedge, the hedging instrument, the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness in offsetting the hedged risk will be assessed prospectively and retrospectively. The Company also formally assesses, both at the inception of the hedging relationship and on an ongoing basis, whether the derivatives that are used in hedging relationships are highly effective in offsetting changes in cash flows of hedged transactions. For derivative instruments that are designated and qualify as part of a cash flow hedging relationship, the gain or loss on the derivative is reported as a component of other comprehensive loss and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings.
The Company discontinues hedge accounting prospectively, when it determines that the derivative is no longer highly effective in offsetting cash flows attributable to the hedged risk, the derivative expires or is sold,
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terminated, or exercised, the originally forecasted transaction is no longer probable of occurring or if management decides to remove the designation of the cash flow hedge. The net derivative instrument gain or loss related to a discontinued cash flow hedge shall continue to be reported in accumulated other comprehensive loss and reclassified into earnings in the same period or periods during which the originally hedged transaction affects earnings, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period. When it is probable that the originally forecasted transaction will not occur by the end of the originally specified time period, the Company recognizes immediately, in earnings, any gains and losses related to the hedging relationship that were recognized in accumulated other comprehensive loss. In all situations in which hedge accounting is discontinued and the derivative remains outstanding, the Company continues to carry the derivative at its fair value on the consolidated balance sheets and recognizes any subsequent changes in the derivative’s fair value in earnings.
In addition, we evaluate the terms of our operating agreements and other contracts, if any, to determine whether they contain embedded components that are required to be bifurcated and accounted for separately as derivative financial instruments. For additional detailed information regarding reportable segments, see Note (10) Derivatives.
(j) Fair Value Measurement
Fair value represents the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the reporting date. The Company’s assets and liabilities that are measured at fair value at each reporting date are classified according to a hierarchy that prioritizes inputs and assumptions underlying the valuation techniques. The Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible. The Company determines fair value based on assumptions that market participants would use in pricing an asset or liability in the principal or most advantageous market. When considering market participant assumptions in fair value measurements, the following fair value hierarchy distinguishes between observable and unobservable inputs, which are categorized in one of the following levels:
•Level 1 Inputs: Quoted prices (unadjusted) in an active market for identical assets or liabilities.
•Level 2 Inputs: Other than quoted prices included in Level 1 inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the asset or liability.
•Level 3 Inputs: Unobservable inputs for the asset or liability used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at measurement date.
Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. Reclassifications of fair value between Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter.
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Notes to the Consolidated Financial Statements
(k) Stock-based compensation
The Company recognizes compensation expense for restricted stock awards, restricted stock units to be settled in common stock (“RSUs”), performance based RSU award (“PSUs”), and non-qualified stock options (“stock options”) based on the fair value of the awards at the date of grant. The fair value of restricted stock awards and RSUs is determined based on the number of shares or RSUs granted and the closing price of the Company’s common stock on the date of grant. The fair value of stock options is determined by applying the Black-Scholes model to the grant-date market value of the underlying common shares of the Company. The fair value of PSUs with market conditions is determined using a Monte Carlo simulation method. The Company has elected to recognize forfeiture credits for these awards as they are incurred, as this method best reflects actual stock-based compensation expense.
Compensation expense from time-based restricted stock awards, RSUs, PSUs, and stock options is amortized on a straight-line basis over the requisite service period, which is generally the vesting period.
Deferred compensation expense associated with liability-based awards, such as deferred stock awards that are expected to settle with the issuance of a variable number of shares based on a fixed monetary amount at inception, is recognized at the fixed monetary amount at inception and is amortized on a straight-line basis over the requisite service period, which is generally the vesting period. Upon settlement, the holders receive an amount of common stock equal to the fixed monetary amount at inception, based on the closing price of the Company’s stock on the date of settlement.
Tax deductions on the stock-based compensation awards are not realized until the awards are vested or exercised. The Company recognizes deferred tax assets for stock-based compensation awards that will result in future deductions on its income tax returns, based on the amount of tax deduction for stock-based compensation recognized at the statutory tax rate in the jurisdiction in which the Company will receive a tax deduction. If the tax deduction for a stock-based award is greater than the cumulative GAAP compensation expense for that award upon realization of a tax deduction, an excess tax benefit will be recognized and recorded as a favorable impact on the effective tax rate. If the tax deduction for an award is less than the cumulative GAAP compensation expense for that award upon realization of the tax deduction, a tax shortfall will be recognized and recorded as an unfavorable impact on the effective tax rate. Any excess tax benefits or shortfalls will be recorded as discrete, adjustments in the period in which they occur. The cash flows resulting from any excess tax benefit will be classified as financing cash flows in the consolidated statements of cash flows.
The Company provides its employees with the option to settle income tax obligations arising from the vesting of their restricted or deferred stock-based compensation awards by withholding shares equal to such income tax obligations. Shares acquired from employees in connection with the settlement of the employees’ income tax obligations are accounted for as treasury shares that are subsequently retired. Restricted stock awards, RSUs, and PSUs are not considered issued and outstanding for purposes of earnings per share calculations until vested.
For additional information, see Note (12) Stock-Based Compensation.
(l) Taxes
Upon consummation of a series of organizational transactions (the “Organizational Transactions”) and the IPO, the Company became subject to U.S. federal income taxes. A provision for U.S. federal income tax has been provided in the consolidated financial statements for the years ended December 31, 2021, 2020 and 2019.
Prior to 2019, the Company had a Canadian subsidiary, which was treated as a corporation for Canadian federal and provincial tax purposes. For Canadian tax purposes, the Company was subject to foreign income tax. As a result of the C&J Merger, the Company had foreign subsidiaries as of December 2020 in Canada, The Netherlands, Luxembourg and Ecuador. With the exception of the Canadian subsidiary, all other subsidiaries are dormant and have no active operations as of December 31, 2021.
The Company is responsible for certain state income and franchise taxes in the states in which it operates, which include, but not limited to California, Colorado, Louisiana, Montana, New Mexico, North Dakota, Oklahoma,
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Pennsylvania, Texas, Utah and West Virginia. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and tax carryforwards, if applicable.
Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years 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 earnings in the period that includes the enactment date.
The Company recognizes interest accrued related to unrecognized tax benefits, if any, in income tax expense.
See Note (17) Income Taxes for a detailed discussion of the Company’s taxes and activities thereof during the years ended December 31, 2021, 2020 and 2019.
(m) Commitments and Contingencies
The Company accrues for contingent liabilities when such contingencies are probable and reasonably estimable. The Company generally records losses related to these types of contingencies as direct operating expenses or general and administrative expenses in the consolidated statements of operations and comprehensive loss.
Legal costs associated with the Company’s loss contingencies are recognized immediately when incurred as general and administrative expenses in the Company’s consolidated statements of operations and comprehensive loss.
(n) Equity-method investments
Investments in non-controlled entities over which the Company has the ability to exercise significant influence over the noncontrolled entities’ operating and financial policies are accounted for under the equity-method. Under the equity-method, the investment in the non-controlled entity is initially recognized at cost and subsequently adjusted to reflect the Company’s share of the entity’s income (losses), any dividends received by the Company and any other-than-temporary impairments. Investments accounted for under the equity-method are presented within other noncurrent assets in the consolidated balance sheets. The Company did not have any equity-method investments as of December 31, 2021 or December 31, 2020.
(o) Employee Benefits and Post-Employment Benefits
Contractual termination benefits are payable when employment is terminated due to an event specified in the provisions of a social/labor plan, state or federal law. Accordingly, in situations where minimum statutory termination benefits must be paid to the affected employees, the Company records employee severance costs associated with these activities in accordance with ASC 712, “Compensation—Nonretirement Post-Employment Benefits.” In all other situations where the Company pays termination benefits, including supplemental benefits paid in excess of statutory minimum amounts and benefits offered to affected employees based on management’s discretion, the Company records these termination costs in accordance with ASC 420, “Exit or Disposal Cost Obligations.” A liability is recognized for one-time termination benefits when the Company is committed to 1) making payments and the number of affected employees and the benefits received are known to both parties and 2) terminating the employment of current employees according to a detailed formal plan without possibility of withdrawal for which such amount can be reasonably estimated.
(p) Leases
Effective January 1, 2019, the Company adopted ASU 2016-02, "Leases (Topic 842)," and related amendments, which set out the principles for the recognition, measurement, presentation and disclosure of leases for both lessees and lessors, using the modified retrospective method. In connection with the adoption of these standards, the Company implemented internal controls to ensure that the Company's contracts are properly evaluated
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to determine applicability under ASU 2016-02 and that the Company properly applies ASU 2016-02 in accounting for and reporting on all its qualifying leases.
In accordance with ASU 2016-02, the Company considers any contract that conveys the right to control the use of identified property, plant or equipment for a period of time in exchange for consideration to be a lease. The Company determines whether the contract into which it has entered is a lease at the lease commencement date. Rental arrangements with term lengths of one month or less are expensed as incurred, but not recognized as qualifying leases.
For lessees, leases can be classified as finance leases or operating leases, while for lessors, leases can be classified as sales-type leases, direct financing leases or operating leases. As lessee, all leases, with the exception of short-term leases, are capitalized on the balance sheet by recording a lease liability, which represents the Company's obligation to make lease payments arising from the lease and a right-of-use asset, which represents the Company's right to use the underlying asset being leased.
For leases in which the Company is the lessee, the Company uses a collateralized incremental borrowing rate to calculate the lease liability, as for most leases, the implicit rate in the lease is unknown. The collateralized incremental borrowing rate is based on a yield curve over various term lengths that approximates the borrowing rate the Company would receive if it collateralized its lease arrangements with all of its assets. For leases in which the Company is the lessor, the Company uses the rate implicit in the lease.
For finance leases, the Company amortizes the right-of-use asset on a straight-line basis over the earlier of the useful life of the right-of-use asset or the end of the lease term and records this amortization in rent expense on the consolidated statements of operations and comprehensive loss. The Company adjusts the lease liability to reflect lease payments made during the period and interest incurred on the lease liability using the effective interest method. The incurred interest expense is recorded in interest expense on the consolidated statements of operations and comprehensive loss. For operating leases, the Company recognizes one single lease cost, comprised of the lease payments and amortization of any associated initial direct costs, within rent expense on the consolidated statements of operations and comprehensive loss. Variable lease costs not included in the determination of the lease liability at the commencement of a lease are recognized in the period when the specified target that triggers the variable lease payments becomes probable.
In accordance with ASC 842, the Company has made the following elections for its lease accounting:
•all short-term leases with term lengths of 12 months or less will not be capitalized; the underlying class of assets to which the Company has applied this expedient is primarily its apartment leases;
•for non-revenue contracts containing both lease and non-lease components, both components will be combined and accounted for as one lease component and accounted for under ASC 842; and
•for revenue contracts containing both lease and non-lease components, both components will be combined and accounted for as one component and accounted for under ASC 606.
As part of the Company's adoption of ASU 2016-02, the Company elected to adopt the standard using the modified retrospective transition method and elected the practical expedient transition method package whereby the Company did not:
•reassess whether any expired or existing contracts contained leases;
•reassess the lease classification for any expired or existing leases; and
•reassess initial direct costs for any existing leases.
For additional information, see Note (16) Leases.
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Notes to the Consolidated Financial Statements
(q) Research and development costs
Research and development costs are expensed as incurred as general and administrative expenses in the Company’s consolidated statements of operations and comprehensive loss. Research and development costs incurred directly by the Company were $5.0 million, $4.8 million and $7.1 million for the years ended December 31, 2021, 2020 and 2019, respectively..
(3) Mergers and Acquisitions
(a) Alamo Acquisition
On August 31, 2021 (the “Alamo Acquisition Date”), the Company completed the Alamo Acquisition in accordance with the terms of the Purchase Agreement, dated as of August 4, 2021 (the “Purchase Agreement”), by and among the Company, NexTier Completion Solutions Inc., Alamo Frac Holdings, LLC, Alamo and the “owner group” identified therein. The Company acquired 100% of Alamo.
The Alamo Acquisition was completed for cash consideration of $100.0 million, equity consideration of 26 million shares of the Company’s common stock valued at $82.3 million, post-closing services valued at $30 million, an estimated $15.9 million of contingent consideration, $7.4 million of non-contingent consideration, and a net working capital settlement of $0.5 million that was finalized in the fourth quarter of 2021 and is to be paid to the Company in early 2022. The contingent consideration includes the Tier II Upgrade Payment, and the Earnout Payments, which are contingent upon the achievement of certain performance targets, as described in the Purchase Agreement.
The Company accounted for the Alamo Acquisition using the acquisition method of accounting. The aggregate purchase price noted above was allocated to the assets acquired and liabilities assumed based upon their estimated fair values at the date of the acquisition. The measurements of some assets acquired and liabilities assumed, such as intangible assets and the earnout were based on inputs that are not observable in the market and thus represent Level 3 inputs. The fair value of acquired property and equipment were based on both available market date and a cost approach.
The following table summarizes the fair value of the consideration transferred in the Alamo Acquisition and the allocation of the purchase price to the fair values of the assets acquired and liabilities assumed at the Alamo Acquisition Date:
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Notes to the Consolidated Financial Statements
| Total Purchase Consideration: | ||||||||||||||||||||
| Preliminary Purchase Price Allocation | Adjustments | Final Purchase Price Allocation | ||||||||||||||||||
| (Thousands of Dollars) | ||||||||||||||||||||
Cash consideration(1) | $ | 100,000 | $ | — | $ | 100,000 | ||||||||||||||
| Equity consideration | 82,323 | — | $ | 82,323 | ||||||||||||||||
| Post close services | 30,000 | — | $ | 30,000 | ||||||||||||||||
| Contingent consideration | 15,944 | — | $ | 15,944 | ||||||||||||||||
| Non contingent consideration | 7,370 | — | $ | 7,370 | ||||||||||||||||
| Net working capital adjustment | — | (482) | $ | (482) | ||||||||||||||||
| Total purchase consideration | $ | 235,637 | $ | (482) | $ | 235,155 | ||||||||||||||
Cash | $ | 7,419 | $ | — | $ | 7,419 | ||||||||||||||
Trade and accounts receivable | 50,619 | — | $ | 50,619 | ||||||||||||||||
Inventories | 1,726 | — | $ | 1,726 | ||||||||||||||||
Prepaid and other current assets | 19,654 | — | $ | 19,654 | ||||||||||||||||
| Assets held for sale | 3,282 | — | $ | 3,282 | ||||||||||||||||
| Property and equipment | 114,705 | (816) | $ | 113,889 | ||||||||||||||||
| Intangible assets | 27,113 | — | $ | 27,113 | ||||||||||||||||
| Finance lease right-of-use assets | 35,813 | (468) | $ | 35,345 | ||||||||||||||||
| Other noncurrent assets | 1,676 | — | $ | 1,676 | ||||||||||||||||
Total identifiable assets acquired | 262,007 | (1,284) | 260,723 | |||||||||||||||||
Accounts payable | 39,101 | — | $ | 39,101 | ||||||||||||||||
Accrued expenses | 38,000 | — | $ | 38,000 | ||||||||||||||||
| Current maturities of long-term finance lease liabilities | 10,125 | — | $ | 10,125 | ||||||||||||||||
| Long-term finance lease liabilities | 25,688 | (468) | $ | 25,220 | ||||||||||||||||
Non-current liabilities | 971 | — | $ | 971 | ||||||||||||||||
Total liabilities assumed | 113,885 | (468) | 113,417 | |||||||||||||||||
Goodwill | 87,515 | 334 | $ | 87,849 | ||||||||||||||||
| Total purchase consideration | $ | 235,637 | $ | (482) | $ | 235,155 | ||||||||||||||
(1) Includes $32.3 million of payments for indebtedness on behalf of Alamo.
Goodwill is calculated as the excess of the consideration transferred over the fair value of the net assets acquired. All the goodwill recognized for the Alamo acquisition is recognized in the Completions segment and is tax deductible with an amortization period of 15 years. The goodwill in this acquisition was primarily attributable to Alamo's organized workforce and potential synergies.
Intangible assets related to the Alamo Acquisition consisted of the following:
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Notes to the Consolidated Financial Statements
| (Thousands of Dollars) | ||||||||||||||
| Weighted average remaining amortization period (Years) | Gross Carrying Amounts | |||||||||||||
| Trademarks | 1.5 | $ | 2,409 | |||||||||||
| Non-compete agreements | 3 | 1,677 | ||||||||||||
| Customer relationships | 7.33 | 23,027 | ||||||||||||
| Total | $ | 27,113 | ||||||||||||
For the valuation of the customer relationship intangible assets within the Completions Services segment, management used the income based multi-period excess earning method, which utilized contributory asset changes. Under this method, the Company calculated earnings derived from the existing customer relationships and then deducted portions of the earnings that could be attributed to supporting assets that contribute to the generation of said earnings. Estimated cash flows were discounted at the cost of equity based on the assumption that the intangible asset would be financed with 100% equity. For the valuation of the trademarks intangible asset within the Completions Services segment, management used the relief from royalty method to reflect the after tax royalty savings attributable to owning the intangible asset. Management used the return on asset method to determine an implied royalty rate since a royalty rate was not available in the Company’s industry. For the valuation of the non-compete agreements intangible asset within the Completions Services segment, management used the incremental cash flow (“with/without”) method.
The Company has recognized $19.0 million in indemnification assets related to an ongoing sales & use tax audit and other indemnified liabilities under the Purchase Agreement.
The following transactions were recognized separately from the acquisition of assets and assumptions of liabilities in the Alamo Acquisition. Merger costs consist of legal and professional fees. Integration costs consist of expenses incurred to integrate Alamo’s operations with that of the Company, including retention bonuses and severance payments. The expenses for all these transactions were expensed as incurred and are presented in Merger and integration in the consolidated statements of operations and comprehensive loss.
| (Thousands of Dollars) | ||||||||
| Transaction Type | Year Ended December 31, 2021 | |||||||
| Merger | $ | 5,592 | ||||||
| Integration | 3,117 | |||||||
| Total merger and integration costs | $ | 8,709 | ||||||
The following combined pro forma information assumes the Alamo Acquisition occurred on January 1, 2020. The pro forma information presented below is for illustrative purposes only and does not reflect future events that occurred after December 31, 2021 or any operating efficiencies or inefficiencies that resulted from the Alamo Acquisition. The information is not necessarily indicative of results that would have been achieved had the company controlled Alamo during the period presented. Pro forma adjustments related to the elimination of historical interest expense for debt paid off as part of the Alamo Acquisition were $2.7 million and $6.9 million for the year ended December 31, 2021 and 2020, respectively.
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| (unaudited, amounts in Thousands of Dollars) | ||||||||||||||
| Year Ended December 31 | ||||||||||||||
| 2021 | 2020 | |||||||||||||
| Revenue | $ | 1,633,866 | $ | 1,451,342 | ||||||||||
| Net loss | (105,400) | (331,283) | ||||||||||||
| Net loss per share (basic) | (0.44) | (1.38) | ||||||||||||
| Net loss per share (diluted) | (0.44) | (1.38) | ||||||||||||
The Company’s condensed consolidated statement of operations and comprehensive loss for the year ended December 31, 2021 includes revenue of $172.1 million and net income of $20.0 million from the Alamo operations.
(b) C&J Energy Services, Inc.
On October 31, 2019, the Company completed the C&J Merger in accordance with the terms of the Agreement and Plan of Merger, dated as of June 16, 2019 (the "Merger Agreement"), by and among NexTier, C&J and King Merger Sub Corp., a wholly owned subsidiary of NexTier ("Merger Sub"), pursuant to which Merger Sub merged with and into C&J, with C&J surviving the merger as a wholly owned subsidiary of NexTier, and immediately following the C&J Merger, C&J was merged with and into King Merger Sub II LLC ("LLC Sub"), with LLC Sub continuing as the surviving entity as a wholly-owned subsidiary of NexTier and the successor in interest to C&J.
The C&J Merger was completed for total consideration of approximately $485.1 million, consisting of (i) equity consideration in the form of 105.9 million shares of common stock issued to C&J stockholders with a value of $481.9 million and (ii) replacement share based compensation awards attributable to pre-merger services with a value of $3.2 million.
The Company accounted for the C&J Merger using the acquisition method of accounting. The aggregate purchase price noted above was allocated to the major categories of assets acquired and liabilities assumed based upon their estimated fair values at the date of the acquisition. The majority of the measurements of assets acquired and liabilities assumed, were based on inputs that were not observable in the market and thus represented Level 3 inputs. The fair value of acquired inventory and property and equipment was based on both available market data and a cost approach. The fair value of the financial assets acquired included trade receivables with a fair value of $312.6 million. The gross amount due under the contracts was $322.8 million, of which $10.2 million was expected to be uncollectible. A liability of $40.2 million was recognized for legal reserves and sales and use tax assessments.
The following table summarizes the fair value of the consideration transferred in the C&J Merger and the allocation of the purchase price to the fair values of the assets acquired and liabilities assumed at the C&J Merger Date:
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Notes to the Consolidated Financial Statements
Total Purchase Consideration: | (Thousands of Dollars) | |||||||
| Equity consideration | $ | 481,912 | ||||||
| Replacement awards attributable to pre-combination services | 3,212 | |||||||
| Less: Cash acquired | (68,807) | |||||||
| Total purchase consideration | $ | 416,317 | ||||||
Trade and accounts receivable | $ | 312,620 | ||||||
Inventories | 43,142 | |||||||
Prepaid and other current assets | 18,512 | |||||||
Property and equipment | 311,886 | |||||||
Intangible assets | 17,590 | |||||||
Right of use assets | 24,318 | |||||||
Other noncurrent assets | 4,409 | |||||||
Total identifiable assets acquired | 732,477 | |||||||
Accounts payable | 43,620 | |||||||
Accrued expenses | 236,959 | |||||||
Short term lease liability | 7,842 | |||||||
Long term lease liability | 15,517 | |||||||
Non-current liabilities | 17,156 | |||||||
Total liabilities assumed | 321,094 | |||||||
Goodwill | 4,934 | |||||||
| Total purchase consideration | $ | 416,317 | ||||||
The goodwill in this acquisition was primarily attributable to expected synergies and was allocated across the Company’s Completion Services, Well Construction and Intervention and Well Support Services reporting units.
Intangible assets related to the C&J Merger consisted of the following:
| (Thousands of Dollars) | ||||||||||||||
| Weighted average remaining amortization period (Years) | Gross Carrying Amounts | |||||||||||||
| Technology | 3 | 17,590 | ||||||||||||
| Total | $ | 17,590 | ||||||||||||
Merger and integration related costs were recognized separately from the acquisition of assets and assumptions of liabilities in the C&J Merger. Merger costs consist of legal and professional fees and pre-merger notification fees. Integration costs consist of expenses incurred to integrate C&J’s operations, aligning accounting processes and procedures, and integrating its enterprise resource planning system with those of the Company. The expenses for all these transactions were expensed as incurred.
Merger and integration costs related to the C&J Merger totaled $32.5 million and $68.7 million for the years ended December 31, 2020 and 2019, respectively, and are recorded within merger and integration costs on the Company’s consolidated statements of operations and comprehensive loss. The following table summarizes merger and integration costs for the years ended December 31, 2020 and 2019. There were no merger and integration costs related to the C&J Merger during the year ended December 31, 2021.
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Notes to the Consolidated Financial Statements
| (amounts in thousands) | ||||||||||||||
| Transaction Type | Year Ended December 31, 2020 | Year Ended December 31, 2019 | ||||||||||||
Merger | $ | 7,586 | $ | 23,775 | ||||||||||
Integration | 24,953 | 44,956 | ||||||||||||
Total merger and integration costs | $ | 32,539 | $ | 68,731 | ||||||||||
The following combined pro forma information assumes the C&J Merger occurred on January 1, 2018. The pro forma information presented below is for illustrative purposes only and does not reflect future events that occurred after December 31, 2019 or any operating efficiencies or inefficiencies that resulted from the C&J Merger. The information is not necessarily indicative of results that would have been achieved had the Company controlled C&J during the period presented.
| (unaudited, amounts in thousands) | ||||||||||||||
| Year Ended December 31, 2019 | Year Ended December 31, 2018 | |||||||||||||
Revenue | $ | 3,406,288 | $ | 4,359,095 | ||||||||||
Net income (loss) | (196,577) | 66,746 | ||||||||||||
Net income (loss) per share (basic) | $ | (0.93) | $ | 0.32 | ||||||||||
Net income (loss) per share (diluted) | $ | (0.93) | $ | 0.31 | ||||||||||
Weighted-average shares outstanding (basic) | 211,376 | 210,945 | ||||||||||||
Weighted-average shares outstanding (diluted) | 211,376 | 212,964 | ||||||||||||
The Company’s consolidated statement of operations and comprehensive income (loss) for 2019 includes revenue of $196.7 million and net loss of $21.4 million, from the C&J operations, from November 1, 2019 to December 31, 2019.
(4) Intangible Assets
The definite-lived intangible assets balance in the Company’s consolidated balance sheets represents the fair value measurement upon initial recognition, net of amortization, as applicable, related to the following:
| (Thousands of Dollars) | ||||||||||||||||||||
| December 31, 2021 | ||||||||||||||||||||
| Gross Carrying Amounts | Accumulated Amortization | Net Carrying Amount | ||||||||||||||||||
Customer contracts | $ | 90,627 | $ | (44,063) | $ | 46,564 | ||||||||||||||
Non-compete agreements | 2,377 | (611) | 1,766 | |||||||||||||||||
| Trademarks | 2,409 | (157) | 2,252 | |||||||||||||||||
Technology | 32,226 | (17,847) | 14,379 | |||||||||||||||||
Total | $ | 127,639 | $ | (62,678) | $ | 64,961 | ||||||||||||||
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Notes to the Consolidated Financial Statements
| (Thousands of Dollars) | ||||||||||||||||||||
| December 31, 2020 | ||||||||||||||||||||
| Gross Carrying Amounts | Accumulated Amortization | Net Carrying Amount | ||||||||||||||||||
Customer contracts | $ | 67,600 | $ | (37,607) | $ | 29,993 | ||||||||||||||
Non-compete agreements | 700 | (455) | 245 | |||||||||||||||||
Technology | 29,378 | (8,434) | 20,944 | |||||||||||||||||
Total | $ | 97,678 | $ | (46,496) | $ | 51,182 | ||||||||||||||
Amortization expense related to the intangible assets for the years ended December 31, 2021, 2020 and 2019 was $16.4 million, $12.6 million and $6.5 million, respectively.
In connection with the C&J Merger, the Company was re-branded as NexTier and did not expect to obtain any further benefits or receive any cash flows associated with the Keane indefinite-lived trade name. As a result, the Company impaired $10.2 million related to the Keane trade name as of December 31, 2019. The impairment is recorded in impairment expense in the consolidated statements of operations and comprehensive loss.
Amortization for the Company’s definite-lived intangible assets, excluding in-process software, over the next five years, is as follows:
| Year-end December 31, | (Thousands of Dollars) | |||||||
| 2022 | $ | (19,457) | ||||||
| 2023 | (12,336) | |||||||
| 2024 | (9,876) | |||||||
| 2025 | (8,452) | |||||||
| 2026 | (5,633) | |||||||
(5) Goodwill
Goodwill is allocated across three reporting units: Completion Services, Well Construction and Intervention Services and Well Support Services reporting units. At the reporting unit level, the Company tests goodwill for impairment on an annual basis as of October 31 of each year, or when events or changes in circumstances, referred to as triggering events, indicate the carrying value of goodwill may not be recoverable and that a potential impairment exists.
Judgment is used in assessing whether goodwill should be tested for impairment more frequently than annually. Factors such as unexpected adverse economic conditions, competition, market changes, and other external events may require more frequent assessments.
During the first quarter of 2020, a significant decline in the Company's share price, which resulted in the Company's market capitalization dropping below the book value of equity, as well as reductions in commodity prices driven by the potential impact of the COVID-19 pandemic and global supply and demand dynamics were deemed triggering events that led to a test for goodwill impairment. The impairment testing methodologies for the first quarter 2020 are discussed below.
Income approach
The income approach impairment testing methodology is based on a discounted cash flow model, which utilizes present values of cash flows to estimate fair value. For the Completions Services and Well Construction and Intervention reporting units, the future cash flows were projected based on estimates of projected revenue growth, unit count, utilization, pricing, gross profit rates, SG&A rates, working capital fluctuations and capital expenditures. Forecasted cash flows took into account known market conditions as of March 31, 2020, and management’s
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Notes to the Consolidated Financial Statements
anticipated business outlook. A terminal period was used to reflect an estimate of stable, perpetual growth. The terminal period reflects a terminal growth rate of 2.5%. The future cash flows were discounted using a market-participant risk-adjusted weighted average cost of capital (“WACC”) of 19.9% for the Completions reporting unit and 22.4% for the Well Construction and Intervention reporting unit. These assumptions were derived from both observable and unobservable inputs and combined reflect management’s judgments and assumptions.
Market approach
The market approach impairment testing methodology is based upon the guideline public company method and the guideline transaction method. The application of the guideline public company method was based upon selected public companies operating within the same industry as the Company. Based on this set of comparable competitor data, operational multiples were derived for the reporting units weighted based on management’s assessment of reliability. The forward-looking selected market multiples for the guideline public company method were enterprise value to revenue and enterprise value to EBITDA multiples, with multiples ranging from 0.5x to 0.6x for revenues and from 3.3x to 6.2x for EBITDA. The application of the guideline transaction method was based upon valuation multiples derived from actual control transactions for comparable companies. Based on this, valuation multiples are derived from historical data of selected transactions, then evaluated and adjusted, if necessary, based on the strengths and weaknesses of the subject reporting unit relative to each acquired guideline company. The forward-looking selected market multiples for the guideline transaction method were enterprise value to revenue and enterprise value to book value of invested capital, with multiples ranging from 0.7x to 2.1x for revenues and from 0.6x to 1.3x for book value of invested capital.
The fair value determined under the market approach is sensitive to these market multiples, and a decline in any of the multiples could reduce the estimated fair value of the reporting unit below its carrying value. Earnings estimates were derived from unobservable inputs that require significant estimates, judgments and assumptions as described in the income approach.
Reconciliation of value and goodwill impairment conclusion
The estimated fair value determined under the income approach was consistent with the estimated fair value determined under the market approach. The concluded fair value for both reporting units consisted of a weighted average, with a 40.0% weighted under the income approach and 60.0% weight under the market approach. Market data in support of the implied control premium were used in this reconciliation to corroborate the estimated reporting unit fair values with the Company's overall market-indicated value. The results of the impairment testing for goodwill resulted in the Company recognizing an impairment expense of $32.6 million during the first quarter of 2020, consisting of $32.2 million related to the Completions Services reporting unit and $0.4 million representing the entire balance of goodwill for the Well Construction and Intervention reporting unit.
During the third quarter of 2020, the Company assessed and deemed the sustained reductions in commodity prices and continuing market economic disruptions as a triggering event. As a result of the triggering event, the Company performed a test for goodwill impairment using the same methodologies used in the first quarter of 2020; however, no impairment of goodwill was recorded.
During the Company’s annual testing as of October 31, 2020 and October 31, 2021, it was determined that there were no events that would indicate the carrying value of goodwill may not be recoverable or that a potential impairment exists.
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Notes to the Consolidated Financial Statements
The changes in the carrying amount of goodwill for the years ended December 31, 2021, 2020 and 2019 were as follows:
| (Thousands of Dollars) | |||||
| Goodwill as of December 31, 2019 | $ | 137,458 | |||
| Disposition of Well Support Services reporting unit | (660) | ||||
| Impairment expense | (32,600) | ||||
| Goodwill as of December 31, 2020 | 104,198 | ||||
| Completions Acquisition | 733 | ||||
| Alamo Acquisition | 87,849 | ||||
| Goodwill as of December 31, 2021 | $ | 192,780 | |||
The changes in the carrying amount of goodwill for the year ended December 31, 2021 consisted of amounts related to the completions acquisition and the Alamo acquisition. The changes in the carrying amount of goodwill for the year ended December 31, 2020 consisted of amounts related to the disposition of the Well Support Services reporting unit, and impairment expense. For additional information, see Note (3) (Mergers and Acquisitions) and Note (21) (Business Segments). As discussed above, in 2020 the Company recognized impairment expense of $32.6 million. There were no triggering events and no impairment expense recorded for the years ended 2021 and 2019.
(6) Inventories, net
Inventories, net, consisted of the following at December 31, 2021 and December 31, 2020:
| (Thousands of Dollars) | ||||||||||||||
| December 31, 2021 | December 31, 2020 | |||||||||||||
| Sand, including freight | $ | 9,674 | $ | 5,096 | ||||||||||
| Chemicals and consumables | 4,204 | 2,993 | ||||||||||||
| Materials and supplies | 24,216 | 21,979 | ||||||||||||
| Total inventory, net | $ | 38,094 | $ | 30,068 | ||||||||||
Inventories are reported net of obsolescence reserves of $6.3 million and $4.4 million as of December 31, 2021 and 2020, respectively. The Company recognized $1.9 million, $2.6 million and $0.8 million of obsolescence expense during the years ended December 31, 2021, 2020 and 2019. Additionally, during the year ended December 31, 2020, the Company recognized a $2.7 million write-down in inventory carrying value down to its net realizable value.
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Notes to the Consolidated Financial Statements
(7) Property and Equipment, net
Property and Equipment, net consisted of the following at December 31, 2021 and December 31, 2020:
| (Thousands of Dollars) | ||||||||||||||
| December 31, 2021 | December 31, 2020 | |||||||||||||
Land | $ | 13,317 | $ | 14,397 | ||||||||||
Building and leasehold improvements | 75,892 | 78,078 | ||||||||||||
Office furniture, fixtures and equipment | 11,846 | 11,400 | ||||||||||||
Machinery and equipment | 1,424,317 | 1,284,163 | ||||||||||||
| 1,525,372 | 1,388,038 | |||||||||||||
Less accumulated depreciation | (951,170) | (929,290) | ||||||||||||
Construction in progress | 46,663 | 11,963 | ||||||||||||
Total property and equipment, net | $ | 620,865 | $ | 470,711 | ||||||||||
Casualty Loss
On May 9, 2021, one of the Company’s hydraulic fleets operating in the Permian Basin was involved in an accidental fire, which resulted in a complete loss of the equipment; no parties were injured as a result of this incident. During the year ended December 31, 2021 the Company recognized a total of $22.9 million in insurance proceeds, partially offset by the $12.5 million loss recognized on the damaged equipment and costs to remove the equipment. The resulting $10.4 million gain was recognized in other income (expense), net in the consolidated statements of operations and comprehensive loss.
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Notes to the Consolidated Financial Statements
(8) Long-Term Debt
Long-term debt at December 31, 2021 and December 31, 2020 consisted of the following:
| (Thousands of Dollars) | ||||||||||||||
| December 31, 2021 | December 31, 2020 | |||||||||||||
2018 Term Loan Facility | 337,750 | $ | 341,250 | |||||||||||
| 2021 Equipment Loans | 41,321 | — | ||||||||||||
| Other long-term debt | 533 | — | ||||||||||||
| Less: Unamortized debt discount and debt issuance costs | (4,719) | (5,710) | ||||||||||||
Total debt, net of unamortized debt discount and debt issuance costs | 374,885 | 335,540 | ||||||||||||
Less: Current portion | (13,384) | (2,252) | ||||||||||||
Long-term debt, net of unamortized debt discount and debt issuance costs | $ | 361,501 | $ | 333,288 | ||||||||||
Below is a summary of the Company’s credit facilities outstanding as of December 31, 2021:
| (Thousands of Dollars) | ||||||||||||||||||||
| 2021 Equipment Loans | 2019 ABL Facility | 2018 Term Loan Facility | ||||||||||||||||||
Original facility size | $ | 46,500 | $ | 450,000 | $ | 350,000 | ||||||||||||||
Outstanding balance | $ | 41,321 | $ | — | $ | 337,750 | ||||||||||||||
Letters of credit issued | $ | — | $ | 23,200 | $ | — | ||||||||||||||
Available borrowing base commitment | n/a | $ | 205,615 | n/a | ||||||||||||||||
Interest Rate(1) | 5.25 | % | LIBOR or base rate plus applicable margin | LIBOR or base rate plus applicable margin | ||||||||||||||||
Maturity Date | June 1, 2025 | October 31, 2024 | May 25, 2025 | |||||||||||||||||
(1) London Interbank Offer Rate (“LIBOR”) is subject to a 1.00% floor
Maturities of the 2018 Term Loan Facility and the 2021 Equipment Loans for the next five years are presented below:
| Year-end December 31, | (Thousands of Dollars) | |||||||
| 2022 | $ | 14,738 | ||||||
| 2023 | 15,430 | |||||||
| 2024 | 15,790 | |||||||
| 2025 | 333,646 | |||||||
| 2026 | — | |||||||
| $ | 379,604 | |||||||
Deferred Charges and Other Costs
Deferred charges include deferred financing costs and debt discounts or debt premiums. Deferred charges related to the 2019 ABL Facility (defined below) are capitalized. Deferred charges related to the 2018 Term Loan Facility (defined below) and the 2021 Equipment Loans (defined below) are netted against the carrying amount of term debt. Deferred charges are amortized to interest expense using the effective interest method. Interest expense related to the deferred financing costs for the years ended December 31, 2021, 2020 and 2019 was $2.1 million, $2.2 million, and $1.4 million, respectively.
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Notes to the Consolidated Financial Statements
Equipment Loans
On August 20, 2021, the Company entered into the Master Loan and Security Agreement the (“Master Agreement”) with Caterpillar Financial Services Corporation. The Master Agreement provides for secured equipment financing term loans in an aggregate amount of up to $46.5 million the (“Equipment Loans”). The Equipment Loans may be drawn in multiple tranches, with each loan evidenced by a separate promissory note. On September 3, 2021 entered into a term note for $39.4 million the (“Note”) for an equipment financing loan. On December 30, 2021 the Company entered into a term note for $3.4 million for additional equipment financing. The Note will bear interest at a rate of 5.25% per annum and has a maturity date of June 1, 2025. The Note will bear interest at a rate of 5.25% per annum and has a maturity date of June 1, 2025. The Company will amortize $0.2 million in debt issuance costs and debt discount over the life of the loan.
ABL Revolving Credit Facility
On October 31, 2019, the Company entered into the Second Amended and Restated Asset-Based Revolving Credit Agreement (“2019 ABL Facility”), modifying the Company’s pre-existing asset-based revolving credit facility (“2017 ABL Facility”). Deferred charges associated with the 2019 ABL Facility were capitalized and totaled $1.2 million. In connection with the modification of the 2017 ABL Facility, the Company wrote off $0.5 million of deferred financing costs. The remaining deferred financing costs related to the 2017 ABL Facility will be amortized over the life of the 2019 ABL Facility. Unamortized deferred charges associated with the 2019 and 2017 ABL Facilities were $2.3 million and $3.1 million as of December 31, 2021 and 2020, respectively, and are recorded in other noncurrent assets on the consolidated balance sheets. During the first quarter of 2020, the Company provided notice to the lenders to borrow a total of $175 million under the 2019 ABL Facility. The interest rates for the $150.0 million LIBOR borrowing and $25.0 million Base Rate borrowing were 2.125% and 3.75%, respectively as of the borrowing dates. During the second quarter of 2020, the Company repaid the $150.0 million LIBOR borrowing and the $25.0 million Base Rate borrowing and did not incur any penalties.
Term Loan Facility
On May 25, 2018, the Company entered into a term loan facility (the “2018 Term Loan Facility”), the proceeds of which were used to repay the Company’s pre-existing term loan facility (the “2017 Term Loan Facility”). No prepayment penalties were incurred in connection with the Company’s early debt extinguishment of its 2017 Term Loan Facility. Deferred charges associated with the 2017 Term Loan Facility that were expensed upon repayment of the 2017 Term Loan Facility totaled $7.6 million. Deferred charges associated with the 2018 Term Loan Facility that were netted against the carrying amount of the term debt totaled $9.0 million. Unamortized deferred charges associated with the 2018 Term Loan Facility were $4.5 million and $5.7 million as of December 31, 2021 and 2020, respectively, and are recorded in long-term debt, net of deferred financing costs and debt discount, less current maturities on the consolidated balance sheets.
(9) Significant Risks and Uncertainties
Subsequent to the sale of the Well Support Services segment, the Company operates in two reportable segments: Completion Services and Well Construction and Intervention, with significant concentration in the Completion Services segment. During the years ended December 31, 2021, 2020 and 2019, sales to Completion Services customers represented 93%, 87% and 94% of the Company’s consolidated revenue, respectively.
The Company depends on its customers' willingness to make operating and capital expenditures to explore for, develop and produce oil and natural gas onshore in the U.S. This activity is driven by many factors, including current and expected crude oil and natural gas prices. From December 28, 2018 through December 31, 2019, U.S. active rig count decreased by approximately 26% to 805 rigs as market conditions tightened and competition within the completions industry increased.
In late 2019 and early 2020, and in response to the oversupply of hydraulic fracturing equipment, an increasing number of horsepower retirements were announced, removing a significant base of equipment from the market. Despite some of these announcements, the oversupply of hydraulic fracturing equipment persisted, resulting in a continuation of highly competitive market conditions into 2020.
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NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
In late first quarter of 2020, the industry faced sudden and unprecedented circumstances, including major shocks to both supply and demand. COVID-19 resulted in significant demand destruction for oil products, driven by a significant slowdown in economic activity throughout the U.S. and abroad. This resulted in a rapid and significant decline in crude oil prices and an increasingly utilized storage network, limiting distribution outlets and optionality for production and further exacerbating price declines. U.S. exploration and production companies responded with drastic reductions in budgets and outright completion stoppages. From the end of the fourth quarter of 2019 through mid-August 2020, the U.S. active rig count decreased by 70%, from 805 to 244 rigs before recovering to 351 rigs by the end of 2020. In 2021, the U.S. active rig count recovery continued, increasing 67% from 351 rigs at the end of 2020 to 586 rigs by the end of 2021.
This backdrop drastically impacted the demand for U.S. completions services and resulted in increased demand for our services throughout 2021 relative to 2020. By the end of 2021, we started to see signs of improving supply/demand dynamics for U.S. onshore completion services, which resulted in improved pricing and margins relative to earlier in 2021. The magnitude, cadence, and resilience of activity and margin improvement, including supply chain disruptions and inflationary pressures, is uncertain and dependent on a range of factors including COVID-19 demand resolution.
For the year ended December 31, 2021, revenue from one customer individually represented approximately 14% of the Company’s consolidated revenue. This customer represented $193.4 million of our consolidated revenue in the Completions Services segment. For the year ended December 31, 2020, two customers individually represented more than 10% and collectively represented 29% of the Company’s consolidated revenue. These two customers represented $188.6 million and $160.5 million, respectively, of our consolidated revenue in the Completions Services segment. For the year ended December 31, 2019, four customers individually represented more than 10% and collectively represented 55% of the Company’s consolidated revenue. These four customers represented $346.9 million, $242.1 million, $213.4 million, and $194.7 million, respectively, of our consolidated revenue in the Completions Services segment.
For the years ended December 31, 2021 and 2020, purchases from one supplier represented approximately 5% of the Company’s overall purchases, and were primarily incurred within the Completion Services segment.
(10) Derivatives
The Company uses interest-rate-related derivative instruments to manage its variability of cash flows associated with changes in interest rates on its variable-rate debt.
On March 9, 2020, the Company sold its Well Support Services segment to Basic Energy Services, Inc. (“Basic”) for $93.7 million of total proceeds, including $59.4 million in cash, before transaction costs, escrowed amounts, and subject to customary working capital adjustments, for a net of $53.3 million received at close, and $34.4 million of par value Senior Secured Notes, with 10.75% coupon rate, (“WSS Notes”) previously issued by Basic. On July 29, 2020, the Company agreed to use the escrowed amount in the final settlement of the working capital reconciliation. Under the terms of the agreement, the WSS Notes are accompanied by a make-whole guarantee at par value, which guarantees the payment of $34.4 million to NexTier after the WSS Notes are held to the one-year anniversary of March 9, 2021. The cash equivalent make-whole is issued under a fund guarantee by Ascribe III Investments LLC, a private equity investment firm with approximately $1.0 billion in assets under management. In the event of a Basic restructuring or a credit rating downgrade in conjunction with a change in control prior to the one-year anniversary, the make-whole guarantee accelerates the WSS Notes to par value of $34.4 million. NexTier is entitled to semi-annual interest payments on the WSS Notes based on the 10.75% annual coupon throughout the holding period. The Company identified the make-whole guarantee as an embedded derivative and bifurcated the valuation of the WSS Note and the make-whole guarantee. The Company elected the fair value option for the WSS Notes at the inception of the transaction. The fair value on the date of the transaction for the make-whole derivative and WSS Notes was $12.2 million and $22.2 million, respectively, and resulted in a gain on divestiture of $8.7 million. The fair value of the WSS Notes and the make-whole guarantee are measured at the end of each reporting period. Unrealized gains and losses recognized in relation to the change in fair value of these instruments are recognized in net loss in the consolidated statements of operations and comprehensive loss. The fair
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Notes to the Consolidated Financial Statements
value of the WSS Notes and make-whole guarantee are recorded in Other Current Assets on the consolidated balance sheets. See Note (21) Business Segments for further discussion.
On March 31, 2021, the Company received a $34.4 million cash payment from Ascribe in full settlement of the WSS Notes and the make-whole guarantee. At the time of the cash payment, the WSS Notes and make-whole guarantee had a fair value of $33.6 million, resulting in a realized gain on settlement of $0.8 million. This gain is recorded within other income (expense) on the consolidated statements of operations and comprehensive loss.
On May 25, 2018, the Company, and certain subsidiaries of the Company as guarantors, entered into the 2018 Term Loan Facility. The 2018 Term Loan Facility has an initial aggregate principal amount of $350.0 million and proceeds were used to repay the Company's pre-existing 2017 term loan facility. The 2018 Term Loan Facility has a variable interest rate based on the LIBOR, subject to a 1.0% floor. In June 2018, the Company executed a new off-market interest rate swap effective through March 31, 2025 to hedge 50% of its expected LIBOR exposure matching the swap to the 1-month LIBOR, 1% floor, of the 2018 Term Loan Facility, and terminated the pre-existing interest rate swaps. After completing all appropriate accounting treatment, including the $3.5 million of deferred gains in accumulated other comprehensive loss for the pre-existing interest rate, the new interest rate swap was designated in a new cash flow hedge relationship.
The following tables present the fair value of the Company’s derivative instruments on a gross and net basis as of the periods shown below:
| (Thousands of Dollars) | |||||||||||||||||||||||||||||
| Derivatives designated as hedging instruments | Derivatives not designated as hedging instruments | Gross Amounts of Recognized Assets and Liabilities | Gross Amounts Offset in the Balance Sheet(1) | Net Amounts Presented in the Balance Sheet(2) | |||||||||||||||||||||||||
| As of December 31, 2021: | |||||||||||||||||||||||||||||
Other current liability | (2,787) | — | (2,787) | — | (2,787) | ||||||||||||||||||||||||
Other noncurrent liability | (3,747) | — | (3,747) | — | (3,747) | ||||||||||||||||||||||||
| As of December 31, 2020: | |||||||||||||||||||||||||||||
Other current asset | $ | — | $ | 27,243 | $ | 27,243 | $ | — | $ | 27,243 | |||||||||||||||||||
Other current liability | (2,861) | — | (2,861) | — | (2,861) | ||||||||||||||||||||||||
Other noncurrent liability | (8,260) | — | (8,260) | — | (8,260) | ||||||||||||||||||||||||
(1) Agreements are in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements.
(2) There are no amounts subject to an enforceable master netting arrangement that are not netted in these amounts. There are no amounts of related financial collateral received or pledged.
The following table presents gains and losses for the Company’s interest rate derivatives designated as cash flow hedges (in thousands of dollars):
| Year Ended December 31, | ||||||||||||||||||||||||||
| 2021 | 2020 | 2019 | Location | |||||||||||||||||||||||
| Amount of loss recognized in other comprehensive income on derivative | $ | 1,703 | $ | (6,422) | $ | (7,628) | OCI | |||||||||||||||||||
| Amount of gain (loss) reclassified from accumulated other comprehensive loss into earnings | (2,741) | (2,334) | 239 | Interest Expense | ||||||||||||||||||||||
The gain (loss) recognized in other comprehensive income for the derivative instrument is presented within the hedging activities line item in the consolidated statements of operations and comprehensive loss.
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Notes to the Consolidated Financial Statements
There were no gains or losses recognized in earnings as a result of excluding amounts from the assessment of hedge effectiveness. Based on recorded values at December 31, 2021, $3.0 million of net losses will be reclassified from accumulated other comprehensive loss into earnings within the next 12 months.
The Company recognized a loss on the change in fair market value of the WSS Notes and make-whole derivative of $0.9 million for the year ended December 31, 2020 which is recorded within other income (expense) on the consolidated statements of operations and comprehensive loss.
See Note (11) Fair Value Measurements and Financial Information for further information related to the Company’s derivative instruments.
(11) Fair Value Measurements and Financial Information
The Company discloses the required fair values of financial instruments in its assets and liabilities under the hierarchy guidelines, in accordance with GAAP. The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, accrued expenses, derivative instruments, long-term debt and finance lease obligations. As of December 31, 2021, and 2020, the carrying values of the Company’s financial instruments, included in its consolidated balance sheets, approximated or equaled their fair values.
Recurring Fair Value Measurement
As of December 31, 2021, the Company has three financial instruments measured at fair value on a recurring basis which are its interest rate derivative (see Note (10) Derivatives above), the equity security investment, and the Earnout Payments. The equity security investment is composed primarily of common equity shares in a publicly traded company, acquired at a fair value of $5.3 million. The equity security investment is presented within other current assets in the consolidated balance sheets, while the interest rate derivative and the Earnout Payments are presented within other current liabilities and other noncurrent liabilities in the consolidated balance sheets. As of December 31, 2020, the Company had four financial instrument measured on a recurring basis, which was its interest rate derivative, make-whole derivative, WSS Note (see Note (10) Derivatives above) and equity security investment.
The fair market value of the derivative financial instruments reflected on the consolidated balance sheets as of December 31, 2021, and 2020 was determined using industry-standard models that consider various assumptions, including current market and contractual rates for the underlying instruments, time value, implied volatilities, nonperformance risk, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace through the full term of the instrument and can be supported by observable data.
The following tables present the placement in the fair value hierarchy of assets and liabilities that were measured at fair value on a recurring basis at December 31, 2021, and 2020 (in thousands of dollars):
| Fair value measurements at reporting date using | ||||||||||||||||||||||||||
| December 31, 2021 | Level 1 | Level 2 | Level 3 | |||||||||||||||||||||||
Assets: | ||||||||||||||||||||||||||
| Equity security investment | $ | 7,743 | $ | 7,743 | $ | — | $ | — | ||||||||||||||||||
Liabilities: | ||||||||||||||||||||||||||
| Earnout Payments | (11,795) | — | — | (11,795) | ||||||||||||||||||||||
| Interest rate derivative | $ | (6,534) | $ | — | $ | (6,534) | $ | — | ||||||||||||||||||
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Notes to the Consolidated Financial Statements
| Fair value measurements at reporting date using | ||||||||||||||||||||||||||
| December 31, 2020 | Level 1 | Level 2 | Level 3 | |||||||||||||||||||||||
Assets: | ||||||||||||||||||||||||||
| Make-whole derivative | $ | 27,243 | $ | — | $ | 27,243 | $ | — | ||||||||||||||||||
| WSS Note | 6,322 | — | 6,322 | $ | — | |||||||||||||||||||||
| Equity security investment | 11,263 | 11,263 | — | $ | — | |||||||||||||||||||||
Liabilities: | ||||||||||||||||||||||||||
| Interest rate derivatives | $ | (11,121) | $ | — | $ | (11,121) | $ | — | ||||||||||||||||||
Non-Routine Fair Value Measurement
The fair values of indefinite-lived assets and long-lived assets are determined with internal cash flow models based on significant unobservable inputs. The Company measures the fair value of its property, plant and equipment using the discounted cash flow method, the fair value of its customer contracts using the multi-period excess earning method and income based “with and without” method, the fair value of its trade names and acquired technology using the “income-based relief-from-royalty” method and the fair value of its non-compete agreement using the “lost income” approach. Assets acquired as a result of the acquisition of the C&J and Alamo transactions were recorded at their fair values on the date of acquisition. See Note (3) Mergers and Acquisitions for further details.
Given the unobservable nature of the inputs used in the Company’s internal cash flow models, the cash flows models are deemed to use Level 3 inputs.
Credit Risk
The Company’s financial instruments exposed to concentrations of credit risk consist primarily of cash and cash equivalents, derivative contracts and trade receivables.
The Company’s cash balances on deposit with financial institutions totaled $110.7 million and $276.0 million as of December 31, 2021 and 2020, respectively, which exceeded Federal Deposit Insurance Corporation insured limits. The Company regularly monitors these institutions’ financial condition.
The credit risk from the derivative contract derives from the potential failure of the counterparty to perform under the terms of the derivative contracts. The Company minimizes counterparty credit risk in derivative instruments by entering into transactions with high-quality counterparties, whose Standard & Poor’s credit rating is higher than BBB. The derivative instruments entered into by the Company do not contain credit-risk-related contingent features.
The majority of the Company’s trade receivables have payment terms of 30 to 60 days or less. Significant customers are those that individually account for 10% or more of the Company’s consolidated revenue or total accounts receivable. As of December 31, 2021, trade receivables from one customer individually represented 17% of the Company’s total accounts receivable. As of December 31, 2020, trade receivables from one customer individually represented 17% of the Company’s total accounts receivable.
The Company mitigates the associated credit risk by performing credit evaluations and monitoring the payment patterns of its customers. The Company has a process in place to collect all receivables within 30 to 60 days of aging. As of December 31, 2021, the Company had $1.9 million in allowance for credit losses. As of December 31, 2020, the Company had $2.7 million in allowance for credit losses, including the increase of $1.5 million from the adoption of ASU 2016-13.
The Company recognized $2.0 million of bad debt expense, net of recoveries during the year ended December 31, 2021. During the year ended December 31, 2020, the Company had $2.0 million of recoveries from previously written-off receivables, net of bad debt expense. During the year ended December 31, 2019, the Company recorded bad debt expense of $0.6 million.
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Notes to the Consolidated Financial Statements
(12) Stock-Based Compensation
Effective as of October 31, 2019, the Company (i) amended and restated the Keane Group, Inc. Equity and Incentive Award Plan under the name NexTier Oilfield Solutions Inc. Equity and Incentive Award Plan (“Equity and Incentive Award Plan”), and (ii) assumed and amended and restated the C&J Energy Services, Inc. 2017 Management Incentive Plan under the name NexTier Oilfield Solutions Inc. (Former C&J Energy) Management Incentive Plan ( “Management Incentive Plan”, and collectively with the Equity and Incentive Award Plan, the “Equity Award Plans”). As part of the C&J Merger, the Company assumed the award agreements outstanding under the Management Incentive Plan on the terms set forth in the Merger agreement.
As of December 31, 2021, the Company had four types of stock-based compensation under its Equity Award Plans: (i) restricted stock awards issued to independent directors and certain executives and employees, (ii) restricted stock units issued to executive officers and key management employees, (iii) non-qualified stock options issued to executive officers and (iv) performance-based restricted stock units issued to executive officers and key management employees. The Company has approximately 7,844,941 shares of its common stock reserved and available for grant under the Equity and Incentive Award Plan.
For details on the Company’s accounting policies for determining stock-based compensation expense, see Note (2) Summary of Significant Accounting Policies: (k) Stock-based compensation. Non-cash stock compensation expense is generally presented within selling, general and administrative expense in the consolidated statements of operations and comprehensive loss however, for the year ended December 31, 2020, the Company presented $2.7 million within merger and integration. These amounts primarily relate to the accelerated vesting of certain awards that contained pre-existing change in control provisions.
The following table summarizes stock-based compensation expense for the years ended December 31, 2021, 2020 and 2019 (in thousands of dollars):
| Year Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
Restricted stock awards | 1,364 | 1,589 | 1,486 | |||||||||||||||||
Restricted stock units | 14,674 | 19,201 | 20,426 | |||||||||||||||||
Non-qualified stock options | 76 | 894 | 3,498 | |||||||||||||||||
Restricted stock performance-based stock unit awards | 8,563 | 4,142 | 3,567 | |||||||||||||||||
Stock-based compensation | $ | 24,677 | $ | 25,826 | $ | 28,977 | ||||||||||||||
Tax benefit | (4,751) | (5,557) | (6,954) | |||||||||||||||||
Stock-based compensation, net of tax | $ | 19,926 | $ | 20,269 | $ | 22,023 | ||||||||||||||
(a) Restricted stock awards
For the years ended December 31, 2021, 2020, and 2019 the Company recognized $1.4 million, $1.6 million, and $1.5 million respectively, of non-cash stock compensation expense. As of December 31, 2021, total unamortized compensation cost related to unvested restricted stock awards was $0.5 million, which the Company expects to recognize over the remaining weighted-average period of 0.45 years.
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Notes to the Consolidated Financial Statements
Rollforward of restricted stock awards as of December 31, 2021 is as follows:
| Number of Restricted Stock Awards (In thousands) | Weighted average grant date fair value | |||||||||||||
| Total non-vested at December 31, 2020 | 623 | $ | 2.27 | |||||||||||
| Shares issued | 256 | 5.67 | ||||||||||||
| Shares vested | (669) | 2.70 | ||||||||||||
| Shares forfeited | — | — | ||||||||||||
| Non-vested balance at December 31, 2021 | 210 | $ | 5.67 | |||||||||||
(b) Restricted stock units
For the years ended December 31, 2021, 2020 and 2019, the Company recognized $14.7 million, $19.2 million and $20.4 million, respectively, of non-cash stock compensation expense. As of December 31, 2021, total unamortized compensation cost related to unvested restricted stock units was $21.9 million, which the Company expects to recognize over the remaining weighted-average period of 1.76 years.
Rollforward of restricted stock units as of December 31, 2021 is as follows:
| Number of Restricted Stock Units (In thousands) | Weighted average grant date fair value | |||||||||||||
| Total non-vested at December 31, 2020 | 4,087 | $ | 6.12 | |||||||||||
| Units issued | 5,909 | 4.08 | ||||||||||||
| Units vested | (1,682) | 6.8 | ||||||||||||
| Units forfeited | (725) | 4.54 | ||||||||||||
| Non-vested balance at December 31, 2021 | 7,589 | $ | 4.53 | |||||||||||
(c) Non-qualified stock options
For the years ended December 31, 2021, 2020 and 2019, the Company recognized $0.1 million, 0.9 million and $3.5 million, respectively, of non-cash stock compensation expense. As of December 31, 2021, the Company did not have any unamortized compensation cost related to unvested stock options.
Rollforward of stock options as of December 31, 2021 is as follows:
| Number of Stock Options (In thousands) | Weighted average grant date fair value | |||||||||||||
| Total outstanding at December 31, 2020 | 1,741 | $ | 4.86 | |||||||||||
| Options granted | — | — | ||||||||||||
| Options exercised | — | — | ||||||||||||
| Actual options forfeited | — | — | ||||||||||||
| Options expired | — | — | ||||||||||||
| Total outstanding at December 31, 2021 | 1,741 | $ | 4.86 | |||||||||||
There were 1.7 million stock options exercisable or vested at December 31, 2021.
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Notes to the Consolidated Financial Statements
Assumptions used in calculating the fair value of the stock options granted during the year are summarized below:
| 2019 Options Granted | 2018 Options Granted | 2017 Options Granted | |||||||||||||||
| Valuation assumptions: | |||||||||||||||||
| Expected dividend yield | 0 | % | 0 | % | 0 | % | |||||||||||
| Expected equity volatility | 49.6 | % | 46.3 | % | 51.5 | % | |||||||||||
| Expected term (years) | 7.3 - 8.1 | 6 | 6 | ||||||||||||||
| Risk-free interest rate | 1.7 | % | 2.7 | % | 1.6 | % | |||||||||||
| Weighted average: | |||||||||||||||||
| Exercise price per stock option | $19.09 - $26.41 | $ | 15.31 | $ | 19.00 | ||||||||||||
| Market price per share | $ | 4.55 | $ | 15.31 | $ | 14.49 | |||||||||||
| Weighted average fair value per stock option | $ | 0.74 | $ | 7.28 | $ | 6.16 | |||||||||||
(d) Performance-based RSU awards
During the first and second quarter of 2021, the Company issued 550,899 and 1,473,736 of performance based RSUs to executive officers under its Equity Award Plans, which were fair valued at $3.2 million and $13.7 million using a Monte Carlo simulation method. Each vesting is subject to a payout percentage based on the Company's annualized total stockholder return ranking relative to its total stockholder return peer group achieved during the performance period. The number of shares that may be earned at the end of the vesting period ranges from —% to 200% of the target award amount, if the performance criteria is met. These performance-based RSUs will be settled in the Company's common stock and are classified as equity awards. The compensation expense associated with these performance-based RSUs will be amortized into earnings on a straight-line basis. As of December 31, 2021, total unamortized compensation cost related to unvested performance-based RSUs was $14.2 million, which the Company expects to recognize over the weighted-average period of 1.91 years.
| Number of Performance-based RSU’s (In thousands) | Weighted average grant date fair value | |||||||||||||
| Total outstanding at December 31, 2020 | 1,268 | $ | 7.15 | |||||||||||
| Performance-based RSU’s issued | 2,220 | 7.91 | ||||||||||||
| Performance-based RSU’s vested | (590) | 3.36 | ||||||||||||
| Performance-based RSU’s forfeited | (50) | 6.27 | ||||||||||||
| Total outstanding at December 31, 2021 | 2,848 | $ | 8.56 | |||||||||||
Assumptions used in calculating the fair value of the first quarter performance-based RSU’s granted during the year are summarized below:
| 2021 Performance based RSU’s Granted | ||||||||
Valuation assumptions: | ||||||||
Expected dividend yield | 0 | % | ||||||
Expected equity volatility, including peers | 55.2% - 147.9% | |||||||
Expected term (years) | 3 | |||||||
Risk-free interest rate | 0.2% - 0.3% | |||||||
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Notes to the Consolidated Financial Statements
(13) Stockholders’ Equity
(a) Vesting of Stock Awards
During the year ended December 31, 2021, 2,162,825 shares were issued, net of share settlements for payment of payroll taxes, upon the vesting of stock-based compensation awards. Shares withheld during the period were immediately retired by the Company.
(b) C&J Merger
As described in Note (3) Mergers and Acquisitions, the Company completed the C&J Merger on October 31, 2019 for total consideration of approximately $485.1 million, consisting of (i) equity consideration in the form of 105.9 million shares of common stock issued to C&J stockholders with a value of $481.9 million and (ii) replacement share based compensation awards attributable to pre-Merger services with a value of $3.2 million.
(c) Alamo Acquisition
As described in Note (3) Mergers and Acquisitions, the Company completed the Alamo Acquisition on August 31, 2021 for total consideration of approximately $235.6 million, consisting of equity consideration in the form of 26 million shares of the Company’s common stock issue to Alamo ownership with a value of $82.3 million.
(14) Accumulated Other Comprehensive Loss
Accumulated other comprehensive loss in the equity section of the consolidated balance sheets includes the following:
| (Thousands of Dollars) | |||||||||||||||||
| Foreign currency items | Interest rate contract | AOCI | |||||||||||||||
| December 31, 2020 | $ | (357) | $ | (12,753) | $ | (13,110) | |||||||||||
| Net income (loss) | — | 2,741 | 2,741 | ||||||||||||||
| Other comprehensive loss | 407 | 1,703 | 2,110 | ||||||||||||||
| December 31, 2021 | $ | 50 | $ | (8,309) | $ | (8,259) | |||||||||||
The following table summarizes reclassifications out of accumulated other comprehensive loss into earnings during years ended December 31, 2021, 2020 and 2019 (in thousands of dollars):
| Year Ended December 31, | Affected line item in the consolidated statements of operations and comprehensive loss | |||||||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||||||||
Interest rate derivatives, hedging | $ | (2,741) | $ | (2,334) | $ | 239 | Interest expense | |||||||||||||||||||
(15) Loss per Share
Basic loss per share is based on the weighted average number of common shares outstanding during the period. Restricted stock awards and RSUs are not considered issued and outstanding for purposes of earnings per share calculations until vested.
Diluted loss per share includes additional common shares that would have been outstanding if potential common shares with a dilutive effect, such as stock awards from the Company’s Equity and Incentive Award Plan, had been issued. Anti-dilutive securities represent potentially dilutive securities that are excluded from the computation of diluted income or (loss) per share as their impact would be anti-dilutive.
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Notes to the Consolidated Financial Statements
A reconciliation of the numerators and denominators used for the basic and diluted net loss per share computations is as follows (in thousands):
| Year Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| Numerator: | ||||||||||||||||||||
| Net loss | $ | (119,423) | $ | (346,883) | $ | (106,157) | ||||||||||||||
| Denominator: | ||||||||||||||||||||
Basic weighted-average common shares outstanding(1) | 224,401 | 213,795 | 122,977 | |||||||||||||||||
| Dilutive effect of restricted stock awards | 145 | 199 | 43 | |||||||||||||||||
| Dilutive effect of RSUs granted under stock incentive plans | 1,140 | 39 | 81 | |||||||||||||||||
| Dilutive effect of performance-based restricted stock awards granted under the Equity Plan | 625 | 1,041 | — | |||||||||||||||||
| Diluted weighted-average common shares outstanding | 226,311 | 215,074 | 123,101 | |||||||||||||||||
(1) As a result of the net loss incurred by the Company for the years ended December 31, 2021, 2020 and 2019, the calculation of diluted net loss per share gives no consideration to the potentially anti-dilutive securities shown in the above reconciliation, and as such is the same as basic net loss per share.
(16) Leases
The Company adopted the new leases standard (ASC 842) effective January 1, 2019, using the modified retrospective transition method. The Company recognized a lease right-of-use asset and lease liability of approximately $61.0 million on its consolidated balance sheet on January 1, 2019, for its operating leases that existed upon the effective date, with no additional impact to its consolidated statements of operations and comprehensive loss or statements of cash flows. The Company also determined that while its hydraulic fracturing fleets represent lease components in its customer contracts, these lease components do not represent the predominant components in its customer contracts. As such the Company has elected to account for the combined components of its customer contracts under the revenue recognition standard. In connection with the adoption of this standard, the Company implemented internal controls to ensure that the Company's contracts are properly evaluated to determine applicability under the new lease standard and that the Company properly applies the standard in accounting for and reporting on all its qualifying leases.
The Company has operating leases for certain of its corporate offices, field shops, apartments, warehouses, rail cars, frac pumps, trailers, tractors and certain other equipment. The Company also has finance leases for its light duty vehicles and frac pumps. The Company acquired the majority of its finance leases as part of the Alamo Acquisition and inherited Alamo’s lease classification as of the time of the acquisition.
The Company's leases have variable payments with annual escalations that are based on the proportion by which the consumer price index ("CPI") for all urban consumers increased over the CPI index for the prior comparative year. The Company's leases have remaining lease terms of less than 1 to 13 years, some of which include extension and termination option. None of these extension and termination options were used to determine the Company's right-of-use assets and lease liabilities, as the Company has not determined it is probable that it will exercise any of these options. None of the Company's leases have residual value guarantees.
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Notes to the Consolidated Financial Statements
The components of the Company's lease costs are as follows:
| (Thousands of Dollars) | ||||||||||||||
Year ended December 31, 2021 | Year ended December 31, 2020 | |||||||||||||
| Operating lease cost | $ | 19,607 | $ | 15,702 | ||||||||||
| Finance lease cost: | ||||||||||||||
| Amortization of right-of-use assets | 1,418 | 2,027 | ||||||||||||
| Interest on lease liabilities | 584 | 269 | ||||||||||||
| Total finance lease cost | 2,002 | 2,296 | ||||||||||||
Short-term and Variable lease cost(1) | 6,537 | 7,469 | ||||||||||||
Sublease income | — | — | ||||||||||||
Total lease cost | $ | 28,146 | $ | 25,467 | ||||||||||
(1)Cost from variable amounts excluded from determination of lease liability.
Supplemental cash flows related to leases are as follows:
Weighted average remaining lease terms are as follows:
Year ended December 31, 2021 | Year ended December 31, 2020 | ||||||||||
| Operating leases | 6.98 years | 4.72 years | |||||||||
| Finance leases | 2.98 years | 1.88 years | |||||||||
Weighted average discount rate on the Company's lease liabilities are as follows:
Year ended December 31, 2021 | Year ended December 31, 2020 | ||||||||||
| Operating leases | 6.83% | 8.65% | |||||||||
| Finance leases | 4.00% | 5.79% | |||||||||
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NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Maturities of the Company's lease liabilities as of December 31, 2021, per ASU 2016-02, were as follows:
| (Thousands of Dollars) | |||||||||||
| Year ending December 31, | Operating leases | Finance leases | |||||||||
| 2022 | $ | 8,709 | $ | 13,001 | |||||||
| 2023 | 5,560 | 17,256 | |||||||||
| 2024 | 3,497 | 10,042 | |||||||||
| 2025 | 2,929 | 923 | |||||||||
| 2026 | 2,275 | — | |||||||||
| Thereafter | 12,022 | — | |||||||||
| Total undiscounted remaining minimum lease payments | 34,992 | 41,222 | |||||||||
| Less imputed interest | (7,094) | (2,443) | |||||||||
| Total discounted remaining minimum lease payments | 27,898 | $ | 38,779 | ||||||||
During the year ended December 31, 2021, the Company entered into two separate agreements with a supplier to sell some diesel-fueled equipment in exchange for credits used to purchase Tier 4 DGB conversion and conversion kits. As part of the agreement, the Company would lease back the equipment for 18 months. The Company determined that the first agreement did not meet the criteria to be classified as a sale-leaseback transaction and was deemed a failed sale-leaseback. This resulted in the recognition of a finance liability of $15.8 million classified in other current liabilities and other non-current liabilities in the consolidated balance sheets. The second agreement met the criteria to be classified as a sale-leaseback transaction and resulted in the recognition of a right-of-use asset and a finance lease liability of $3.0 million and a finance liability of $1.9 million.
As of December 31, 2021, the Company does not have additional operating and finance leases that have not yet commenced, nor did the Company have any lease transactions with any of its related parties.
(17) Income Taxes
The following table summarizes the income (loss) from continuing operations before income taxes in the following jurisdictions:
| (Thousands of Dollars) | ||||||||||||||||||||
| Year Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| Domestic | $ | (157,713) | $ | (357,250) | $ | (106,879) | ||||||||||||||
| Foreign | 39,976 | 11,837 | 1,727 | |||||||||||||||||
| $ | (117,737) | $ | (345,413) | $ | (105,152) | |||||||||||||||
The components of the Company’s income tax provision are as follows:
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Notes to the Consolidated Financial Statements
| (Thousands of Dollars) | ||||||||||||||||||||
| Year Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| Current: | ||||||||||||||||||||
| State | $ | (54) | $ | (297) | $ | 709 | ||||||||||||||
| Foreign | 1,677 | 1,858 | 627 | |||||||||||||||||
| Total current income tax provision | $ | 1,623 | $ | 1,561 | $ | 1,336 | ||||||||||||||
| Deferred: | ||||||||||||||||||||
| Federal | $ | 55 | $ | (158) | $ | (239) | ||||||||||||||
| State | 8 | 53 | (92) | |||||||||||||||||
| Foreign | — | 14 | — | |||||||||||||||||
| Total deferred income tax provision | 63 | (91) | (331) | |||||||||||||||||
| $ | 1,686 | $ | 1,470 | $ | 1,005 | |||||||||||||||
The following table presents the reconciliation of the Company’s income taxes calculated at the statutory federal tax rate, currently 21%, to the income tax provision in its consolidated statements of operations and comprehensive loss. State income tax benefit is offset by state deferred tax asset calculation adjustment which negates the expected state income tax benefit impact on the financials. The Company’s effective tax rate for 2021 of (1.43)% differs from the statutory rate, primarily due to state taxes, foreign withholding taxes, and a change in the valuation allowance. The Company’s effective tax rate for 2020 was (0.43)%.
| (Thousands of Dollars) | ||||||||||||||||||||
| December 31, 2021 | December 31, 2020 | December 31, 2019 | ||||||||||||||||||
| Income tax provision computed at the statutory federal rate | $ | (24,724) | $ | (72,537) | $ | (22,082) | ||||||||||||||
| Reconciling items: | ||||||||||||||||||||
| State income taxes, net of federal tax benefit | (1,959) | (12,222) | (1,463) | |||||||||||||||||
| Deferred tax asset valuation adjustment | 25,306 | 82,557 | 14,987 | |||||||||||||||||
| Permanent differences | 2,796 | 4,589 | 9,962 | |||||||||||||||||
| Foreign withholding taxes | 1,683 | 1,870 | 627 | |||||||||||||||||
| Other | (1,416) | (2,787) | (1,026) | |||||||||||||||||
| Income tax provision | $ | 1,686 | $ | 1,470 | $ | 1,005 | ||||||||||||||
Deferred income taxes are provided to reflect the future tax consequences or benefits of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements using enacted tax
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Notes to the Consolidated Financial Statements
rates.
| (Thousands of Dollars) | ||||||||||||||||||||
| Year Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| Deferred tax assets: | ||||||||||||||||||||
| Stock-based compensation | $ | 6,247 | $ | 4,972 | $ | 4,124 | ||||||||||||||
| Net operating loss and other carry-forwards | 364,882 | 284,151 | 196,949 | |||||||||||||||||
| Accruals and other | 14,472 | 15,535 | 21,411 | |||||||||||||||||
| PPE & Intangibles | — | — | 1,474 | |||||||||||||||||
| Gross deferred tax assets | 385,601 | 304,658 | 223,958 | |||||||||||||||||
| Valuation allowance | (318,260) | (294,101) | (223,419) | |||||||||||||||||
| Total deferred tax assets | $ | 67,341 | $ | 10,557 | $ | 539 | ||||||||||||||
| Deferred tax liability: | ||||||||||||||||||||
| PP&E and intangibles | $ | (65,163) | $ | (8,317) | $ | — | ||||||||||||||
| Prepaids and other | (2,241) | (2,240) | (645) | |||||||||||||||||
| Total deferred tax liability | (67,404) | (10,557) | (645) | |||||||||||||||||
| Net deferred tax liability | $ | (63) | $ | — | $ | (106) | ||||||||||||||
As of December 31, 2021, NexTier had total U.S. federal tax net operating loss (“NOL”) carryforwards of $1.5 billion, of which, $380.2 million, if not utilized, will begin to expire in the year 2031. The remaining federal NOLS can be carried forward indefinitely. The total deferred tax asset for net operating loss and other carryforwards also includes approximately $40.9 million of interest expense carryovers with indefinite life. Of the federal NOLs that can be carried forward indefinitely, $350.8 million is related to the Company’s current year federal tax loss. The Company has state NOLS of $617.0 million, which if not utilized, will expire in various years between 2025 and 2038. Additionally, the Company has $18.0 million of NOLs in foreign jurisdictions that, if not utilized, will begin to expire in the year 2034.
As a result of the C&J Merger on October 31, 2019, NexTier had a change in ownership for purposes of Section 382 of the Internal Revenue Code (“IRC”). As a result, the amount of pre-change NOLs and other tax attributes that are available to offset future taxable income are subject to an annual limitation. The annual limitation is based on the value of the Company as of the effective date of the C&J Merger. The Company’s Section 382 annual limitation is $8.5 million. In addition, this annual limitation is subject to adjustments from the realization of net unrealized built-in gain (“NUBIG”) during a five-year recognition period ending October 31, 2024. As of December 31, 2021, it is expected that all of the Company’s pre-change NOLs of $398.8 million incurred prior to the C&J Merger will be available for use during the applicable carryforward period without becoming permanently lost by the Company due to expiration. The Company’s pre-change NOLs subject to expiration comprise $275.8 million out of the total $398.8 million.
C&J Energy Services, Inc. had Pre-change NOLs carry forward prior to the C&J Merger. As a result of the C&J Merger, such NOLs were carried over to the Company. These NOLs are also subject to an annual limitation under IRC Section 382. The Company’s annual limitation with respect to the C&J Energy NOLs is $8.6 million and is subject to adjustments from the realization of net unrealized built-in loss (“NUBIL”) during a five-year recognition period ending October 31, 2024. Due to this IRC Section 382 annual limitation, some of the NOLs carried over to the Company from C&J Energy Services, Inc. are expected to become permanently lost by the Company due to the expiration and will not be available for use by the Company during the applicable carryforward period. The Company has not reflected the NOLs expected to expire as a result of this limitation in its summary of deferred tax assets or in the NOLs disclosed within this paragraph. The pre-change NOLs carried over from C&J Energy Services, Inc. including built-in loss through December 31, 2021, total $443.3 million of which $104.4 million are subject to expiration, but not expected to expire as a result of the IRC Section 382 limitation.
ASC 740, “Income Taxes,” requires the Company to reduce its deferred tax assets by a valuation allowance if, based on the weight of the available evidence, it is more likely than not that all or a portion of a deferred tax asset
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Notes to the Consolidated Financial Statements
will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences are deductible. As a result of the Company’s evaluation of both the positive and negative evidence, the Company determined it does not believe it is more likely than not that its deferred tax assets will be utilized in the foreseeable future and has recorded a valuation allowance. The valuation allowance as of December 31, 2021 fully offsets the net deferred tax assets, excluding deferred tax liabilities related to certain indefinite-lived assets. The valuation allowance as of December 31, 2017 fully offsets the impact of the initial benefit recorded related to the formation of NexTier Oilfield Solutions Inc., excluding deferred tax liabilities related to certain indefinite lived assets. This initial deferred impact was recorded as an adjustment to equity due to a transaction between entities under common control. The valuation allowances as of December 31, 2021, 2020, and 2019 were $318.3 million, $294.1 million and $223.4 million, respectively.
Changes in the valuation allowance for deferred tax assets were as follows:
| (Thousands of Dollars) | ||||||||
| Valuation allowance as of the beginning of January 1, 2021 | $ | 294,101 | ||||||
| Charge as (benefit) expense to income tax provision for current activities | 25,306 | |||||||
| Changes to other comprehensive loss | (1,147) | |||||||
| Valuation allowance as of December 31, 2021 | $ | 318,260 | ||||||
The Company may be subject to the Global Intangible Low-Taxed Income (“GILTI”) as a result of its foreign operations. The Company accounts for any U.S. taxable income inclusion under GILTI as a permanent book/tax difference.
There were no unrecognized tax benefits nor any accrued interest or penalties associated with unrecognized tax benefits during the years ended December 31, 2021, 2020 and 2019. The Company believes it has appropriate support for the income tax positions taken and to be taken on the Company’s tax returns, and its accruals for tax liabilities are adequate for all open years based on our assessment of many factors including past experience and interpretations of tax law applied to the facts of each matter. The Company classifies interest and penalties within the provision for income taxes. The Company’s tax returns are open to audit under the statute of limitations for the years ended December 31, 2018 through December 31, 2020 for federal tax purposes and for the years ended December 31, 2017 through December 31, 2020 for state tax purposes.
(18) Commitments and Contingencies
As of December 31, 2021, and 2020, the Company had $1.0 million and $4.9 million of deposits on equipment, respectively. Outstanding purchase commitments on equipment were $54.1 million and $23.4 million, as of December 31, 2021, and 2020, respectively.
As of December 31, 2021, the Company has a letter of credit of $23.2 million under the 2019 ABL Facility.
In the normal course of operations, the Company enters into certain long-term raw material supply agreements for the supply of proppant to be used in hydraulic fracturing. As part of some of these agreements, the Company is subject to minimum tonnage purchase requirements and may pay penalties in the event of any shortfall. The Company purchased $47.8 million, $77.6 million and $160.0 million amounts of proppant under its take-or-pay agreements during the years ended December 31, 2021, 2020 and 2019.
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Notes to the Consolidated Financial Statements
Aggregate minimum commitments under long-term raw material supply agreements with payment penalties for minimum tonnage purchases for the next five years as of December 31, 2021 are listed below:
(Thousands of Dollars) | |||||
| Year-end December 31, | |||||
| 2022 | $ | 33,886 | |||
| 2023 | 5,160 | ||||
| 2024 | 1,190 | ||||
| 2025 | — | ||||
| 2026 | — | ||||
| $ | 40,236 | ||||
Litigation
From time to time, the Company is subject to legal and administrative proceedings, settlements, investigations, claims and actions, as is typical of the industry. These claims include, but are not limited to, contract claims, environmental claims, employment related claims, claims alleging injury or claims related to operational issues and motor vehicle accidents. The Company’s assessment of the likely outcome of litigation matters is based on its judgment of a number of factors, including experience with similar matters, past history, precedents, relevant financial information and other evidence and facts specific to the matter. The Company may increase or decrease its legal accruals in the future, on a matter-by-matter basis, to account for developments in such matters. Notwithstanding the uncertainty as to the final outcome and based upon the information currently available to it, the Company does not currently believe these matters in aggregate will have a material adverse effect on its consolidated financial position, results of operations or liquidity.
Environmental
The Company is subject to various federal, state and local environmental laws and regulations that establish standards and requirements for protection of the environment. The Company cannot predict the future impact of such standards and requirements, which are subject to change and can have retroactive effectiveness. The Company continues to monitor the status of these laws and regulations. Currently, the Company has not been fined, cited or notified of any environmental violations that would have a material adverse effect upon its financial position, liquidity or capital resources. However, management does recognize that by the very nature of the Company’s business, material costs could be incurred in the near term to maintain compliance. The amount of such future expenditures is not determinable due to several factors, including the unknown magnitude of possible regulation or liabilities, the unknown timing and extent of the corrective actions which may be required, the determination of the Company’s liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnification.
Regulatory Audits
Prior to the consummation of the C&J Merger, the Company and C&J had been notified by certain state taxing authorities that these taxing authorities would be conducting routine sales and use tax audits of certain wholly owned operating subsidiaries of the Company for tax periods ranging from January 2011 through December 2019. As of December 31, 2020, the Company had recorded estimates of potential assessments for each audit totaling in the aggregate approximately $33.0 million. For one audit, in particular, the Company disagreed with many aspects of the state’s assessment and began to contest the state’s position through administrative procedures. During the first quarter of 2021, the Company obtained additional information that resulted in a reduction of the Company's accrual related to this tax audit by $13.3 million. During the second quarter of 2021, the Company further reduced the accrual related to this tax audit by $8.8 million, after taking into account additional information obtained, including refund claims relating to such periods. The Company received a final settlement offer from Texas Attorney General Office on September 8, 2021 for $3.7 million, which resulted in an additional reduction to the accrual by $2.8 million. These reductions were recorded in selling, general and administrative expenses in the consolidated statements of operations and comprehensive loss.
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Notes to the Consolidated Financial Statements
Alamo is subject to regulatory audits by state taxing jurisdictions it operates in. There was an ongoing tax audit when the Alamo Acquisition was completed. The Company evaluated the potential assessment and exposures for all taxing jurisdictions and recorded an estimate of $17.7 million. The estimate is included in the purchase price allocation disclosed under Note (3) Alamo Acquisition.
(19) Related Party Transactions
Cerberus Operations and Advisory Company, Cerberus Capital Management, L.P. and Cerberus Technology Solutions LLC, affiliates of the Company’s principal equity holder, provide certain consulting services to the Company. The Company paid $0.6 million, $2.2 million and $4.1 million during the years ended December 31, 2021, 2020 and 2019, respectively.
In connection with the Company’s research and development initiatives, the Company engaged in transactions with its equity-method investee. As of December 31, 2020, the Company had purchased $1.7 million of shares in its equity-method investee. In the first quarter of 2020, the Company had enough evidence to believe that it would not be able to recover its $1.7 million investment in its equity-method investee and completely impaired it. The impairment is recorded in impairment expense in the consolidated statement of operations and comprehensive loss. For additional information, see Note (2) Summary of Significant Accounting Policies.
As part of the Purchase Agreement, the Company agreed to provide certain post-closing services to Alamo Frac Holdings, LLC valued as $30.0 million in the aggregate . During the year ended December 30, 2021, the Company provided services to Alamo Frac Holdings, LLC of $6.3 million as part of the Purchase Agreement. The Company has a remaining customer contract liability related to these services of $23.7 million as of December 31, 2021.
(20) Retirement Benefits and Nonretirement Postemployment Benefits
Defined Contribution Plan
The Company sponsors two different 401(k) defined contribution retirement plans covering eligible employees. The Company makes matching contributions of up to 3.5% of eligible compensation, but suspended the Company matching contribution to the 401(k) plans as of May 1, 2020. Eligible employees can make annual contributions to one of the two plans for which they are eligible up to the maximum amount allowed by current federal regulations, as noted in the plan documents. Due to the suspension of the matching contribution plan, the Company did not make any contributions during the year ended December 31, 2021. Contributions made by the Company related to the years ended December 31, 2020, and 2019 were $4.5 million and $8.1 million, respectively.
Severance
The Company provides severance benefits to certain of its employees in connection with the termination of their employment. Severance benefits offered by the Company were $2.1 million, $27.0 million and $16.7 million for the years ended December 31, 2021, 2020 and 2019, respectively.
(21) Business Segments
In accordance with ASC No. 280, Segment Reporting (“ASC 280”), the Company routinely evaluates whether its separate segments have changed. This determination is made based on the following factors: (1) the Company’s chief operating decision maker (“CODM”) is currently managing each operating segment as a separate business and evaluating the performance of each segment and making resource allocation decisions distinctly and expects to do so for the foreseeable future, and (2) discrete financial information for each operating segment is available.
In 2019, due to the transformative nature of the C&J Merger, the CODM changed the way in which the Company is managed, including the level at which to make performance evaluation and resource allocation decisions. Discrete financial information was created to provide the segment information necessary for the CODM to manage the Company under the revised operating segment structure. On March 9, 2020 the Company announced it had completed the divestiture of its Well Support Services (“WSS”) segment. As a result of the changes to
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Notes to the Consolidated Financial Statements
operating segments, the Company revised its reportable segments subsequent to the completion of the C&J Merger and prior to the WSS divestiture, the Company’s revised reportable segments were: (i) Completion Services and (ii) Well Construction and Intervention Services (“WC&I”) and (iii) Well Support Services. Subsequent to the WSS divestiture, the Company’s reportable segments were (i) Completion Services, and (ii) Well Construction and Intervention Services. This segment structure reflects the financial information and reports used by the Company’s management, specifically including its CODM, to make decisions regarding the Company’s business, including performance evaluation and resource allocation decisions. As a result of the revised reportable segment structure subsequent to the C&J merger, the Company has restated the corresponding items of segment information for all periods presented.
The following is a description of each reportable segment:
Completion Services
The Company’s Completion Services segment consists of the following businesses and service lines: (1) fracturing services; (2) wireline and pumpdown services; and (3) completion support services, which includes the Company's research and technology department.
Well Construction and Intervention Services
The Company’s WC&I segment consists of the following businesses and service lines: (1) cementing services and (2) coiled tubing services.
Historical Segment: Well Support Services
The Company’s Well Support Services segment consisted of the following businesses and service lines: (1) rig services; (2) fluids management services; and (3) other specialty well site services. On March 9, 2020, the Company completed the divestiture of its Well Support Services segment for $93.7 million of total proceeds, including $59.4 million in cash, before transaction costs, escrowed amounts, and subject to customary working capital adjustments, for a net of $53.3 million received at close, and $34.4 million of par value Senior Secured Notes, with 10.75% coupon rate, ("WSS Notes") previously issued by Basic. This resulted in a gain on divestiture of $8.7 million. The gain is recorded within (Gain) Loss on Disposal of Assets on the consolidated statements of operations and comprehensive loss. Income per share for the three months ended March 31, 2020 attributable to the divested Well Support Services segment was less than $0.01. On July 29, 2020, the Company received the escrowed cash amount in final settlement for working capital reconciliation.
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Notes to the Consolidated Financial Statements
The following tables present financial information with respect to the Company’s segments. Corporate and Other represents costs not directly associated with a segment, such as interest expense, income taxes and corporate overhead. Corporate assets include cash, deferred financing costs, derivatives and entity-level machinery equipment.
| Year Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| Operations by reportable segment | ||||||||||||||||||||
| Adjusted gross profit (loss): | ||||||||||||||||||||
Completion Services(1) | $ | 165,867 | $ | 168,276 | $ | 401,845 | ||||||||||||||
WC&I(1) | 10,016 | 9,731 | 7,812 | |||||||||||||||||
Well Support Services(1) | — | 12,338 | 7,967 | |||||||||||||||||
| Total adjusted gross profit | $ | 175,883 | $ | 190,345 | $ | 417,624 | ||||||||||||||
(1) Adjusted gross profit at the segment level is not considered to be a non-GAAP financial measure as it is the Company's segment measure of profitability and is required to be disclosed under GAAP pursuant to ASC 280.
| Year ended December 31, 2021 | ||||||||||||||||||||||||||
| Completion Services | WC&I | Well Support Services | Total | |||||||||||||||||||||||
| Revenue | $ | 1,324,888 | $ | 98,553 | $ | — | $ | 1,423,441 | ||||||||||||||||||
| Cost of Services | 1,165,881 | 89,440 | — | 1,255,321 | ||||||||||||||||||||||
| Gross profit excluding depreciation and amortization | 159,007 | 9,113 | — | 168,120 | ||||||||||||||||||||||
Management adjustments associated with cost of services(1) | 6,860 | 903 | — | 7,763 | ||||||||||||||||||||||
Adjusted gross profit(2) | $ | 165,867 | $ | 10,016 | $ | — | $ | 175,883 | ||||||||||||||||||
(1) Adjustments relate to market-driven severance and restructuring costs incurred as a result of significant declines in crude oil prices resulting from demand destruction from the COVID-19 pandemic and global oversupply.
(2) Adjusted gross profit at the segment level is not considered to be a non-GAAP financial measure as it is the Company’s segment measure of profitability and is required to be disclosed under GAAP pursuant to ASC 280.
| Year ended December 31, 2020 | ||||||||||||||||||||||||||
| Completion Services | WC&I | Well Support Services | Total | |||||||||||||||||||||||
| Revenue | $ | 1,046,314 | $ | 98,338 | $ | 57,929 | $ | 1,202,581 | ||||||||||||||||||
| Cost of Services | 893,785 | 93,198 | 45,591 | 1,032,574 | ||||||||||||||||||||||
| Gross profit excluding depreciation and amortization | 152,529 | 5,140 | 12,338 | 170,007 | ||||||||||||||||||||||
Management adjustments associated with cost of services(1) | 15,747 | 4,591 | — | 20,338 | ||||||||||||||||||||||
Adjusted gross profit(2) | $ | 168,276 | $ | 9,731 | $ | 12,338 | $ | 190,345 | ||||||||||||||||||
(1) Adjustments relate to market-driven severance and restructuring costs incurred as a result of significant declines in crude oil prices resulting from demand destruction from the COVID-19 pandemic and global oversupply.
(2) Adjusted gross profit at the segment level is not considered to be a non-GAAP financial measure as it is the Company’s segment measure of profitability and is required to be disclosed under GAAP pursuant to ASC 280.
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Notes to the Consolidated Financial Statements
| Year ended December 31, 2019 | ||||||||||||||||||||||||||
| Completion Services | WC&I | Well Support Services | Total | |||||||||||||||||||||||
| Revenue | $ | 1,709,934 | $ | 63,039 | $ | 48,583 | $ | 1,821,556 | ||||||||||||||||||
| Cost of Services | 1,308,089 | 55,227 | 40,616 | 1,403,932 | ||||||||||||||||||||||
| Gross profit excluding depreciation and amortization | 401,845 | 7,812 | 7,967 | 417,624 | ||||||||||||||||||||||
Management adjustments associated with cost of services(3) | — | — | — | — | ||||||||||||||||||||||
Adjusted gross profit(2) | $ | 401,845 | $ | 7,812 | $ | 7,967 | $ | 417,624 | ||||||||||||||||||
(2) Adjusted gross profit at the segment level is not considered to be a non-GAAP financial measure as it is the Company’s segment measure of profitability and is required to be disclosed under GAAP pursuant to ASC 280.
(3) Adjustments relate to integration costs recorded in costs of services as a result of the RSI asset acquisition in 2018.
| (Thousands of Dollars) | ||||||||||||||
| December 31, 2021 | December 31, 2020 | |||||||||||||
Total assets by segment: | ||||||||||||||
Completion Services | $ | 1,201,265 | $ | 689,814 | ||||||||||
WC&I | 60,195 | 62,959 | ||||||||||||
Well Support Services | — | — | ||||||||||||
Corporate and Other | 196,121 | 405,115 | ||||||||||||
Total assets | $ | 1,457,581 | $ | 1,157,888 | ||||||||||
Goodwill by segment: | ||||||||||||||
Completion Services | $ | 192,780 | $ | 104,198 | ||||||||||
WC&I | — | — | ||||||||||||
Well Support Services | — | — | ||||||||||||
Corporate and Other | — | — | ||||||||||||
Total goodwill | $ | 192,780 | $ | 104,198 | ||||||||||
(22) New Accounting Pronouncements
(a) Recently Adopted Accounting Standards
In December 2019, the Financial Accounting Standards Board issued ASU No. 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes” (“ASU 2019-12”). ASU 2019-12 removes certain exceptions to the general principles in Topic 740 in Generally Accepted Accounting Principles. ASU 2019-12 is effective for public entities for fiscal years beginning after December 15, 2020, with early adoption permitted. The Company adopted this standard on January 1, 2021, and there was no impact on the financial statements.
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Notes to the Consolidated Financial Statements
(b) Recently Issued Accounting Standards
In October 2021, the FASB issued ASU 2021-08 “Business Combinations (Topic 805) Accounting for Contract Assets and Contract Liabilities from Contracts with Customers”. ASU 2021-08 requires acquiring entities to apply Topic 606 to recognize and measure contract assets and contract liabilities in a business combination. This standard is effective beginning on December 15, 2022. The Company does not expect ASU 2021-08 to have any impact on its consolidated financial statements.
In January 2021, the FASB issued ASU 2021-01 “Reference Rate Reform (Topic 848)”. ASU 2021-01 expands on the US GAAP guidance on contract modifications and hedge accounting related to the expected market transition from the London Interbank Offered Rate (LIBOR) and other interbank offered rates to alternative reference rates. This standard is effective beginning on March 12, 2020, and the Company may elect to apply the amendments prospectively through December 31, 2022. The Company is currently evaluating the impact of this standard on its consolidated financial statements and related disclosures.
In October 2020, the FASB issued ASU 2020-10 “Codification Improvements”. ASU 2020-10 improves the clarity and consistency of various provisions in the Codification. This standard was effective for fiscal years beginning after December 15, 2020. ASU 2020-10 did not have any impact on the its consolidated financial statements.
In August 2020, the FASB issued ASU 2020-06 “Debt—Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging—Contracts in Entity's Own Equity (Subtopic 815-40)” (“ASU 2020-06”). ASU 2020-06 simplifies the guidance on the issuer's accounting for convertible debt instruments and convertible preferred stock. This standard was effective for fiscal years beginning after December 15, 2021. ASU 2020-06 did not have any impact on the Company's consolidated financial statements.
In March 2020, the FASB issued ASU 2020-04, “Reference Rate Reform (Topic 848)”, which is intended to provide temporary optional expedients and exceptions to the US GAAP guidance on contract modifications and hedge accounting to ease the financial reporting burdens related to the expected market transition from the London Interbank Offered Rate (LIBOR) and other interbank offered rates to alternative reference rates. This standard is effective beginning on March 12, 2020, and the Company may elect to apply the amendments prospectively through December 31, 2022. The Company is currently evaluating the impact of this standard on its consolidated financial statements and related disclosures.
In January 2020, the FASB issued ASU 2020-01, “Investments—Equity Securities (Topic 321), Investments—Equity Method and Joint Ventures (Topic 323), and Derivatives and Hedging (Topic 815)”, which clarifies the interaction between the accounting for investments in equity securities, investment in equity method and certain derivatives instruments. This standard is expected to reduce diversity in practice and increase comparability of the accounting for these interactions. This standard is effective for fiscal years beginning after December 15, 2021 and the adoption is not expected to have any impact on the Company's consolidated financial statements.
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Item 9. Changes in and Disagreements With Accountant 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 the Chief Executive Officer and Chief Financial Officer, 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) under the Exchange Act) as of the end of the period covered by this report. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of such date. Our disclosure controls and procedures are designed to ensure that information required to be disclosed in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, 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 Rules 13a-15(f) and 15d-15(f) under the Exchange Act).
Internal control over financial reporting, no matter how well designed, has inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to our financial statement preparation and presentation. Further, because of changes in conditions, the effectiveness of internal control over financial reporting may vary over time.
Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation to assess the effectiveness of our internal control over financial reporting as of December 31, 2021, based upon criteria set forth in the “Internal Control - Integrated Framework (2013)” issued by the Committee of Sponsoring Organizations of the Treadway Commission. As permitted by SEC guidance for newly acquired businesses, the scope of management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2021, has excluded the acquired business of Alamo Pressure Pumping, LLC and its subsidiaries (which we refer to herein as “Alamo”). We completed the Alamo Acquisition on August 31, 2021, and the excluded business represents $413.6 million of total assets and total revenues of $172.1 million included in the consolidated financial statements of the Company as of and for the year ended December 31, 2021. Based on our assessment, we believe that as of December 31, 2021, our internal control over financial reporting is effective.
The effectiveness of our internal control over financial reporting as of December 31, 2021 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report that is included herein.
Changes in Internal Control Over Financial Reporting
As disclosed in Note (3) Alamo Acquisition of Part II, “Item 8. Financial Statements and Supplmental Data”, we acquired Alamo on August 31, 2021. As part of the Company’s ongoing integration activities, the Company’s financial reporting controls and procedures are in the process of being implemented at Alamo. The two companies maintained separate accounting systems through December 31, 2021. The consolidated financial statements presented in this Annual Report on Form 10-K were prepared using information obtained from these separate accounting systems.
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Except as described above, there were no changes to our internal control over financial reporting that occurred during the quarter ended December 31, 2021 that have materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information
Continuing Award Program for Qualified Retirees
On February 17, 2022, the compensation committee of our board of directors adopted and approved a Continuing Award Program to provide continued vesting for long-term and short-term incentive awards upon the retirement of Qualified Retirees (the “Continuing Award Program”). The Continuing Award Program is intended and designed to promote a smooth transition for eligible employees nearing retirement. The key highlights of the program are as follows:
•Eligible employees who are at least age 55 and who have at least 5 years of service with the Company (with at least three of the most recent years being with the Company) are eligible for the Continuing Award Program if their combined age and service equals 65.
•Eligible employees may notify the Company of their intended retirement no more than 1 year in advance of retirement and no less than 6 months in advance of their intended retirement.
•If eligible employees comply with the notice requirements and the Company accepts their application for retirement, the eligible employees will continue to vest in their long-term incentive awards through the end of the applicable vesting or performance period for any long-term incentive awards that were granted at least 6 months before their notice date (i.e., they are no longer required to perform services to continue to vest in such awards following retirement).
•Eligible employees who have at least 4 months of service during the short-term incentive plan year during which they retire will also remain eligible for their short-term incentive award for such year.
The remaining terms and conditions of the Company’s long-term and short-term incentive programs remain the same. Accordingly, any performance metrics will continue to apply and payment or settlement of any outstanding awards will occur at the same time and on the same conditions as if the employee had not retired.
The foregoing description of the Continuing Award Program does not purport to be complete and is qualified in its entirety by reference to the full text of the Continuing Award Program, which is filed as Exhibit 10.44 to this Annual Report on Form 10-K and is incorporated herein by reference.
Leadership Severance Program
On February 17, 2022, the compensation committee of our board of directors also adopted and approved a Leadership Severance Program (the “Severance Program”) to provide severance commitments to its named executive officers, as well as its other officers and vice presidents. Under the Severance Program, named executive officers will be eligible for 1.5 times their annual base salary and target short-term incentive award payable in 12 equal installments and 12 months of subsidized COBRA following a termination without Cause (as defined in the Severance Program) or by the executive for Good Reason (as defined in the Severance Program). The named executive officers will be eligible for a prorated short-term incentive award for the year of termination and will also be eligible to fully vest in any RSUs and vest in any PSUs based on actual performance. In the event that the termination of employment without Cause or by the executive for Good Reason occurs within 2 years following a Change in Control (as defined in the Severance Program), the multiple of annual base salary and target short-term incentive award will be increased to 2 times and subsidized COBRA coverage will be provided for 18 months. The named executive officers would also receive the target short-term incentive award for the year of termination and fully vest in any RSUs and vest in any PSUs based on the greater of target or actual performance. In the event of a named executive officer’s disability or death, the executive would be entitled to a prorated short-term incentive award for the year of disability or death and fully vest in any RSUs and vest in any PSUs based on target performance.
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The Severance Program provides similar severance commitments to other officers and vice presidents at reduced levels. All Severance Program benefits are subject to an eligible employee’s timely execution and non-revocation of a release and waiver agreement in favor of the Company and are subject to the Company’s clawback policy.
The foregoing description of the Severance Program does not purport to be complete and is qualified in its entirety by reference to the full text of the Severance Program, which is filed as Exhibit 10.45 to this Annual Report on Form 10-K and is incorporated herein by reference.
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
None.
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PART III
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Item 10. Directors, Executive Officers and Corporate Governance
Incorporated herein by reference from the Company’s definitive proxy statement for its 2022 Annual Meeting of Stockholders, which will be filed no later than 120 days after December 31, 2021.
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Item 11. Executive Compensation
Incorporated herein by reference from the Company’s definitive proxy statement for its 2022 Annual Meeting of Stockholders, which will be filed no later than 120 days after December 31, 2021.
128
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Incorporated herein by reference from the Company’s definitive proxy statement for its 2022 Annual Meeting of Stockholders, which will be filed no later than 120 days after December 31, 2021.
129
Item 13. Certain Relationships and Related-Party Transactions and Director Independence
Incorporated herein by reference from the Company’s definitive proxy statement for its 2022 Annual Meeting of Stockholders, which will be filed than no later 120 days after December 31, 2021.
130
Item 14. Principal Accountant Fees and Services
Incorporated herein by reference from the Company’s definitive proxy statement for its 2022 Annual Meeting of Stockholders, which will be filed no later than 120 days after December 31, 2021.
131
PART IV
Item 15. Exhibits and Financial Schedules
The following documents are filed as part of this report:
Financial Statements
| NexTier Oilfield Solutions Inc. | |||||
| Audited Consolidated Financial Statements | |||||
Reports of Independent Registered Public Accounting Firm | |||||
Consolidated Balance Sheets | |||||
| Consolidated Statements of Operations and Comprehensive Loss | |||||
| Consolidated Statements of Changes in Stockholders’ Equity | |||||
| Consolidated Statements of Cash Flows | |||||
| Notes to Consolidated Financial Statements | |||||
Financial Statement Schedules:
The schedules listed in Rule 5-04 of Regulation S-X (17 CFR 210.5-04) have been omitted because they are not applicable or the required information is shown in the consolidated financial statements or notes thereto.
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Exhibits
The documents listed in the Exhibit Index of this Annual Report on Form 10-K are incorporated by reference or are filed with this Annual Report on Form 10-K, in each case as indicated therein (numbered in accordance with Item 601 of Regulation S-K).
EXHIBIT INDEX
| Exhibit Number | Exhibit Description | |||||||
| Agreement and Plan of Merger, dated as of June 16, 2019, by and among C&J Energy Services, Inc., Keane Group, Inc. and King Merger Sub Corp. (incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed on June 17, 2019). | ||||||||
| Purchase Agreement, dated August 4, 2021, by and among NexTier Completion Solutions Inc., NexTier Oilfield Solution Inc., Alamo Frac Holdings, LLC, Alamo Pressure Pumping, LLC and the Owner Group identified therein (incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed on August 4, 2021). | ||||||||
| Certificate of Incorporation of Keane Group, Inc. dated October 13, 2016 (incorporated by reference to Exhibit 3.1 to the Registrant’s Registration Statement on Form S-1 filed on December 14, 2016). | ||||||||
| Certificate of Amendment to Certificate of Incorporation of Keane Group, Inc. dated October 31, 2019 (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed on October 31, 2019). | ||||||||
| Bylaws (incorporated by reference to Exhibit 3.2 to the Registrant’s Annual Report on Form 10-K filed on March 21, 2017). | ||||||||
| First Amendment to Bylaws (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed on November 2, 2020). | ||||||||
| Second Amended and Restated Stockholders' Agreement, dated October 31, 2019, by and among Keane Group, Inc. and Keane Investor Holdings LLC (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on October 31, 2019). | ||||||||
| Description of Registrant’s Securities (incorporated by reference to Exhibit 4.2 to the Registrant’s Annual Report on Form 10-K filed on March 12, 2020). | ||||||||
| Second Amended and Restated Asset-Based Revolving Credit Agreement, dated October 31, 2019, by and among NexTier Oilfield Solutions Inc. (f/k/a Keane Group, Inc.), Keane Group Holdings, LLC, as the Lead Borrower, certain other subsidiaries of NexTier Oilfield Solutions Inc. as additional borrowers, the guarantors party thereto, the lenders party thereto, and Bank of America, N.A., as administrative and collateral agent (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on October 31, 2019). | ||||||||
| Term Loan Agreement, dated May 25, 2018, by and among Keane Group Inc., as the Parent, Keane Group Holdings, LLC, as the Lead Borrower, the Subsidiary Guarantors party thereto, Barclays Bank PLC, as Administrative Agent and Collateral Agent, and the Lenders from time to time party thereto (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on May 29, 2018). | ||||||||
| Master Loan and Security Agreement, dated August 20, 2021 (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on September 7, 2021). | ||||||||
10.4† | Keane Management Holdings LLC Management Incentive Plan (incorporated by reference to Exhibit 10.6 to the Registrant’s Registration Statement on Form S-1 filed on December 14, 2016). | |||||||
10.5† | NexTier Oilfield Solutions Inc. (Former C&J Energy) Management Incentive Plan, dated effective October 31, 2019 (incorporated by reference to Exhibit 4.4 to the Registrant’s Registration Statement on Form S-8 filed on November 1, 2019). | |||||||
10.6† | Amendment No. 1 to NexTier Oilfield Solutions Inc. (Former C&J Energy) Management Incentive Plan (incorporated by reference to Exhibit 10.50 to the Registrant’s Annual Report on Form 10-K filed on February 24, 2021). | |||||||
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10.7† | NexTier Oilfield Solutions Inc. Equity and Incentive Award Plan (Amended and Restated 2021) (incorporated by reference to Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q filed on August 5, 2021). | |||||||
10.8† | Form of Keane Group, Inc. Executive Incentive Bonus Plan (incorporated by reference to Exhibit 10.8 to the Registrant’s Registration Statement on Form S-1 filed on December 14, 2016). | |||||||
10.9† | Form of Indemnification Agreement (incorporated by reference to Exhibit 10.9 of the Registrant’s Registration Statement on Form S-1 filed on December 14, 2016). | |||||||
| Form of Director Services Agreement (incorporated by reference to Exhibit 10.10 to the Registrant’s Registration Statement on Form S-1 filed on December 14, 2016). | ||||||||
| Keane Group, Inc. Form of Restricted Stock Award (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed on January 26, 2017). | ||||||||
| Keane Group, Inc. Form of Deferred Stock Award Agreement (incorporated by reference to Exhibit 10.23 to the Registrant’s Annual Report on Form 10-K filed on March 21, 2017). | ||||||||
| Form of Keane Group, Inc. Equity and Incentive Award Plan Amendment to Deferred Stock Award Agreement (incorporated by reference to Exhibit 10.29 to the Registrant’s Annual Report on Form 10-K filed on February 27, 2019). | ||||||||
| Form of RSU Award Agreement (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q filed on August 3, 2017). | ||||||||
| Form of Non-Qualified Stock Option Award Agreement (incorporated by reference to Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q filed on August 3, 2017). | ||||||||
| Keane Group, Inc. Form of Restricted Stock Award Agreement for Non-Employee Directors (incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q filed on August 1, 2018). | ||||||||
| Keane Group, Inc. Form of Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.4 to the Registrant’s Quarterly Report on Form 10-Q filed on August 1, 2018). | ||||||||
| Keane Group, Inc. Form of Restricted Stock Unit Performance Award Agreement (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q filed on May 7, 2019). | ||||||||
| Keane Group, Inc. Form of Non-Qualified Stock Option Award Agreement (incorporated by reference to Exhibit 10.5 to the Registrant’s Quarterly Report on Form 10-Q filed on August 1, 2018). | ||||||||
| Form of Amendment to Keane Group, Inc. Restricted Unit Award Agreements with each of James Stewart, Greg Powell, Paul Debonis and Kevin McDonald (incorporated by reference to Exhibit 10.6 to the Registrant’s Quarterly Report on Form 10-Q filed on August 1, 2018). | ||||||||
| Form of Amendment to Keane Group, Inc. Non-Qualified Stock Option Award Agreements with each of James Stewart, Greg Powell, Paul DeBonis and Kevin McDonald (incorporated by reference to Exhibit 10.7 to the Registrant’s Quarterly Report on Form 10-Q filed on August 1, 2018). | ||||||||
| C&J Energy Services, Inc. 2017 Management Incentive Plan (incorporated by reference to Exhibit 10.1 to C&J Energy Services Inc.’s Current Report on Form 8-K filed on January 13, 2017). | ||||||||
| First Amendment to the C&J Energy Services, Inc. 2017 Management Incentive Plan (incorporated by reference to Exhibit 10.1 to C&J Energy Services Inc.’s Current Report on Form 8-K filed on February 6, 2017). | ||||||||
| Second Amendment to the C&J Energy Services, Inc. 2017 Management Incentive Plan (incorporated by reference to Exhibit 10.22 to the Registrant’s Annual Report on Form 10-K filed on March 12, 2020). | ||||||||
| Restricted Share Agreement (C&J Executive Employment Agreements) under the 2017 Management Incentive Plan (incorporated by reference to Exhibit 10.2 to C&J Energy Services Inc.’s Current Report on Form 8-K filed on February 6, 2017). | ||||||||
| Restricted Share Agreement (Restrictive Covenants) under the 2017 Management Incentive Plan (incorporated by reference to Exhibit 10.3 to C&J Energy Services Inc.’s Current Report on Form 8-K filed on February 6, 2017). | ||||||||
| Nonqualified Stock Option Agreement (C&J Executive Employment Agreements) under the 2017 Management Incentive Plan (incorporated by reference to Exhibit 10.5 to C&J Energy Services Inc.’s Current Report on Form 8-K filed on February 6, 2017). | ||||||||
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| Nonqualified Stock Option Agreement (Restrictive Covenants) under the 2017 Management Incentive Plan (incorporated by reference to Exhibit 10.6 to C&J Energy Services Inc.’s Annual Report on Form 8-K filed on February 6, 2017). | ||||||||
| Performance Share Agreement under the 2017 Management Incentive Plan (incorporated by reference to Exhibit 10.10 to C&J Energy Services Inc.’s Annual Report on Form 10-K filed on February 27, 2019). | ||||||||
| Performance Share Agreement (C&J Employment Agreement - Tier I) under the 2017 Management Incentive Plan (incorporated by reference to Exhibit 10.11 to C&J Energy Services Inc.’s Annual Report on Form 10-K filed on February 27, 2019). | ||||||||
| Performance Share Agreement (C&J Employment Agreement - Tier II) under the 2017 Management Incentive Plan (incorporated by reference to Exhibit 10.12 to C&J Energy Services Inc.’s Annual Report on Form 10-K filed on February 27, 2019). | ||||||||
| Restricted Share Unit Agreement (C&J Employment Agreement - Tier I) under the 2017 Management Incentive Plan (incorporated by reference to Exhibit 10.13 to C&J Energy Services Inc.’s Annual Report on Form 10-K filed on February 27, 2019). | ||||||||
| Restricted Share Unit Agreement (C&J Employment Agreement - Tier II) under the 2017 Management Incentive Plan (incorporated by reference to Exhibit 10.14 to C&J Energy Services Inc.’s Annual Report on Form 10-K filed on February 27, 2019). | ||||||||
| Cash Retention Award Agreement (C&J Employment Agreement - Tier I) under the 2017 Management Incentive Plan (incorporated by reference to Exhibit 10.15 to C&J Energy Services Inc.’s Annual Report on Form 10-K filed on February 27, 2019). | ||||||||
| Cash Retention Award Agreement (C&J Employment Agreement - Tier II) under 2017 Management Incentive Plan (incorporated by reference to Exhibit 10.16 to C&J Energy Services Inc’s Annual Report on Form 10-K filed on February 27, 2019). | ||||||||
| Form of RSU Award Agreement 2020 (Executive) (incorporated by reference to Exhibit 10.35 to the Registrant’s Annual Report on Form 10-K filed on March 12, 2020). | ||||||||
Form of PSU Agreement 2020 (incorporated by reference to Exhibit 10.36 to the Registrant’s Annual Report on Form 10-K filed on March 12, 2020). | ||||||||
| Form of RSU Award Agreement 2021 (incorporated by reference to Exhibit 10.37 to the Registrant’s Annual Report on Form 10-K filed on February 24, 2021). | ||||||||
| Form of PSU Award Agreement 2021 (incorporated by reference to Exhibit 10.38 to the Registrant’s Annual Report on Form 10-K filed on February 24, 2021). | ||||||||
10.40†* | Form of Stock Payment Award Agreement. | |||||||
10.41†* | Form of RSU Award Agreement 2022. | |||||||
10.42†* | Form of PSU Award Agreement 2022. | |||||||
10.43†* | Form of Performance Award Agreement 2022. | |||||||
10.44†* | Continuing Award Program for Qualified Retirees. | |||||||
10.45†* | Leadership Severance Program. | |||||||
| Amended and Restated Employment Agreement, dated July 12, 2019, by and between Keane Group, Inc. and Robert Drummond (incorporated by reference to Exhibit 10.2 of the Registrant’s Registration Statement on Form S-4 filed on July 16, 2019). | ||||||||
| Amended Form of Restricted Unit Award Agreement for R. Drummond (incorporated by reference to Registrant’s Quarterly Report on Form 10-Q filed on May 5, 2021). | ||||||||
| Third Amended and Restated Employment Agreement, dated June 16, 2019, by and between Keane Group, Inc. and Greg Powell (incorporated by reference to Exhibit 10.3 of the Registrant’s Registration Statement on Form S-4 filed on July 16, 2019). | ||||||||
| Amended and Restated Employment Agreement, dated July 12, 2019, by and between Keane Group, Inc. and Kevin M. McDonald (incorporated by reference to Exhibit 10.4 of the Registrant’s Registration Statement on Form S-4 filed on July 16, 2019). | ||||||||
135
| Amended and Restated Employment Agreement, dated as of November 1, 2019, by and between NexTier Oilfield Solutions Inc. and Ian J. Henkes (incorporated by reference to Exhibit 10.40 to the Registrant’s Annual Report on Form 10-K filed on March 12, 2020). | ||||||||
| Second Amended and Restated Employment Agreement, dated January 13, 2021, by and between NexTier Oilfield Solutions Inc. and Kenny Pucheu (incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed on January 15, 2021). | ||||||||
| Form of Third Amended and Restated Employment Agreement by and among KGH Intermediate Holdco II, LLC, Keane Group Inc. and James C. Stewart (incorporated by reference to Exhibit 10.11 to the Registrant’s Registration Statement on Form S-1 filed on December 14, 2016). | ||||||||
| Separation Agreement for James Stewart (incorporated by reference to Exhibit 10.48 to the Registrant’s Annual Report on Form 10-K filed on March 12, 2020). | ||||||||
| Employment Agreement, dated February 20, 2017, by and between KGH Intermediate Holdco II, LLC and Phung Ngo-Burns (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on April 4, 2017). | ||||||||
| Amendment to Employment Agreement of Phung Ngo-Burns, dated March 20, 2020 (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on March 24, 2020). | ||||||||
| Employment Agreement, dated August 4, 2021, by and between Alamo Pressure Pumping, LLC and Michael Joseph McKie (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q filed on November 9, 2021). | ||||||||
| Form of Earnout Agreement by and between NexTier Completion Solutions Inc. and Alamo Frac Holdings, LLC (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on August 4, 2021). | ||||||||
| Form of Registration Rights Agreement by and between NexTier Oilfield Solutions Inc. and Alamo Frac Holdings, LLC (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on August 4, 2021). | ||||||||
21.1* | Schedule of Subsidiaries of NexTier Oilfield Solutions Inc. | |||||||
23.1* | Consent of KPMG LLP, Independent Registered Public Accounting Firm. | |||||||
31.1* | Certification of the Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |||||||
31.2* | Certification of the Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |||||||
32.1* | Certifications of the Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |||||||
| 101.INS | XBRL Instance Document | |||||||
| 101.SCH | XBRL Taxonomy Extension Schema Document | |||||||
| 101.CAL | XBRL Taxonomy Extension Calculation Linkbase Document | |||||||
| 101.LAB | XBRL Taxonomy Extension Label Linkbase Document | |||||||
| 101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document | |||||||
| 101.DEF | XBRL Taxonomy Extension Definition Linkbase Document | |||||||
| 104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) | |||||||
† Indicates a management contract or compensatory plan or arrangement.
* Filed herewith.
Item 16. Form 10-K Summary
None.
136
137
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on February 23, 2022.
NexTier Oilfield Solutions Inc. (Registrant) | ||||||||
| By: | /s/ Robert W. Drummond | |||||||
| Robert W. Drummond | ||||||||
| President, Chief Executive Officer and Director | ||||||||
| (Principal Executive Officer) | ||||||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
138
| Signature | Title | Date | ||||||||||||
| /s/ Robert W. Drummond | President, Chief Executive Officer and Director (Principal Executive Officer) | February 23, 2022 | ||||||||||||
| Robert W. Drummond | ||||||||||||||
| /s/ Kenneth Pucheu | Executive Vice President and Chief Financial Officer (Principal Financial Officer) | February 23, 2022 | ||||||||||||
| Kenneth Pucheu | ||||||||||||||
| /s/ Oladipo Iluyomade | Vice President, Chief Accounting Officer and Treasurer (Principal Accounting Officer) | February 23, 2022 | ||||||||||||
| Oladipo Iluyomade | ||||||||||||||
| /s/ James C. Stewart | Director | February 23, 2022 | ||||||||||||
| James C. Stewart | ||||||||||||||
| /s/ Stuart Brightman | Director | February 23, 2022 | ||||||||||||
| Stuart Brightman | ||||||||||||||
| /s/ Gary M. Halverson | Director | February 23, 2022 | ||||||||||||
| Gary M. Halverson | ||||||||||||||
| /s/ Patrick Murray | Director | February 23, 2022 | ||||||||||||
| Patrick Murray | ||||||||||||||
| /s/ Amy H. Nelson | Director | February 23, 2022 | ||||||||||||
| Amy H. Nelson | ||||||||||||||
| /s/ Mel Riggs | Director | February 23, 2022 | ||||||||||||
| Mel Riggs | ||||||||||||||
| /s/ Bernardo Rodriguez | Director | February 23, 2022 | ||||||||||||
| Bernardo Rodriguez | ||||||||||||||
| /s/ Michael Roemer | Director | February 23, 2022 | ||||||||||||
| Michael Roemer | ||||||||||||||
| /s/ Scott Wille | Director | February 23, 2022 | ||||||||||||
| Scott Wille | ||||||||||||||
139
