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As filed with the Securities and Exchange Commission on May 11, 2022

Registration No. 333-261255

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Amendment No. 5

to

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

ProFrac Holding Corp.

(Exact name of registrant as specified in its charter)

 

 

 

Delaware   1389   87-2424964
(State or other jurisdiction of
incorporation or organization)
  (Primary Standard Industrial
Classification Code Number)
  (I.R.S. Employer
Identification Number)

333 Shops Boulevard, Suite 301

Willow Park, Texas 76087

(254) 776-3722

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

 

 

Lance Turner

Chief Financial Officer

333 Shops Boulevard, Suite 301

Willow Park, Texas 76087

(254) 776-3722

(Name, address, including zip code, and telephone number, including area code, of agent for service)

 

 

Copies to:

 

Michael S. Telle

Scott D. Rubinsky

Vinson & Elkins L.L.P.

1001 Fannin Street, Suite 2500

Houston, TX 77002

(713) 758-2222

 

David J. Miller

Jason Ewart

Monica E. White

Latham & Watkins LLP

301 Congress Avenue, Suite 900

Austin, TX 78701

(737) 910-7300

 

 

Approximate date of commencement of proposed sale to the public: As soon as practicable after the effective date of this Registration Statement.

If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.  

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  

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 not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 7(a)(2)(B) of the Securities Act.  

 

 

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until this Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

 

 

 


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The information in this preliminary prospectus is not complete and may be changed. The securities described herein may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell nor does it seek an offer to buy the securities described herein in any jurisdiction where the offer or sale is not permitted.

 

Subject to completion, dated May 11, 2022

Prospectus

16,000,000 shares

 

 

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ProFrac Holding Corp.

Class A common stock

This is our initial public offering. We are offering 16,000,000 shares of our Class A common stock.

Prior to this offering, there has been no public market for our Class A common stock. It is currently estimated that the initial public offering price will be between $21.00 and $24.00 per share of Class A common stock. We have applied to list our Class A common stock on the Nasdaq Global Select Market (“Nasdaq”) under the symbol “PFHC.”

THRC Holdings, LP (“THRC Holdings”) and the Farris and Jo Ann Wilks 2022 Family Trust have indicated that they may collectively purchase in this offering an aggregate of up to $117.0 million, or 5,200,000 shares (based on the midpoint of the price range set forth above), of our Class A common stock at the price to the public. The underwriters will not receive any underwriting discounts or commissions on any shares sold to such potential purchasers. The number of shares available for sale to the general public will be reduced to the extent such potential purchasers purchase such shares. There can be no assurance that any such purchasers will purchase shares in this offering, and, unless otherwise indicated, the information presented in this prospectus assumes that no such purchasers purchase shares of our Class A common stock in this offering, and when so indicated, assumes THRC Holdings purchases 4,222,222 shares of Class A common stock and the Farris and Jo Ann Wilks 2022 Family Trust purchases 977,778 shares of Class A common stock. See “Underwriting” beginning on page 177.

To the extent that the underwriters sell more than 16,000,000 shares of Class A common stock, the underwriters have the option to purchase, exercisable within 30 days from the date of this prospectus, up to an additional 2,400,000 shares of Class A common stock from us at the public offering price less the underwriting discounts and commissions.

We are an “emerging growth company” as that term is used in the Jumpstart Our Business Startups Act of 2012, or JOBS Act, and as such, we have elected to take advantage of certain reduced public company reporting requirements for this prospectus and future filings. See “Risk Factors” and “Summary—Emerging Growth Company.”

Investing in our Class A common stock involves risks. See “Risk Factors” beginning on page 37 to read about factors you should consider before buying shares of our Class A common stock.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

 

     
      Per share      Total  

Initial public offering price

   $                    $                            

Underwriting discounts and commissions(1)

   $        $    

Proceeds, before expenses, to ProFrac Holding Corp.

   $        $    

 

(1)   Please read “Underwriting” for a description of all underwriting compensation payable in connection with this offering.

Delivery of the shares of Class A common stock is expected to be made on or about                 , 2022.

 

J.P. Morgan   Piper Sandler   Morgan Stanley

BofA

Securities

  Capital One Securities  

Johnson Rice &

Company L.L.C.

 

Seaport Global

Securities

  Stifel

 

The date of this prospectus is                 , 2022.


Table of Contents

 

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Table of Contents

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Table of Contents

Table of contents

 

Summary

     1  

The offering

     29  

Summary historical and pro forma financial data

     32  

Cautionary statement regarding forward-looking statements

     35  

Risk factors

     37  

Use of proceeds

     72  

Dividend policy

     74  

Capitalization

     75  

Dilution

     77  

Management’s discussion and analysis of financial condition and results of operations

     79  

Industry overview

     104  

Business

     112  

Management

     136  

Executive compensation

     141  

Corporate Reorganization

     149  

Security ownership of certain beneficial owners and management

     151  

Certain relationships and related party transactions

     153  

Description of capital stock

     164  

Shares eligible for future sale

     170  

Material U.S. federal income tax considerations for non-U.S. holders

     172  

Underwriting

     177  

Legal matters

     183  

Experts

     184  

Where you can find additional information

     185  

Glossary of selected terms

     A-1  

Index to financial statements

     F-1  

 

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About this prospectus

You should rely only on the information contained in this prospectus or in any free writing prospectus prepared by us or on behalf of us or to which we have referred you. We have not, and the underwriters have not, authorized any other person to provide you with information different from that contained in this prospectus and any free writing prospectus. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell the securities described herein in any jurisdiction where an offer or sale is not permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of our common stock. Our business, financial condition, results of operations and prospects may have changed since that date.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. Please read “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”

Unless the context otherwise requires, the information in this prospectus (other than in the historical financial statements) assumes that the underwriters will not exercise their option to purchase additional shares.

Presentation of financial and operating data

ProFrac Holding Corp. was formed on August 17, 2021, and has not conducted and will not conduct any material business operations prior to the completion of the transactions described under “Corporate Reorganization” (such transactions, the “Corporate Reorganization”) other than certain activities related to this offering. Our predecessor consists of ProFrac Holdings, LLC and its subsidiaries (“ProFrac LLC” or “ProFrac”), Best Pump and Flow, LP (“Best Flow”) and Alpine Silica, LLC (“Alpine” and, together with ProFrac LLC and Best Flow, “ProFrac Predecessor”) on a consolidated basis. Historical periods for ProFrac Predecessor had been presented on a consolidated and combined basis given the common control ownership by Dan Wilks and Farris Wilks (or entities they control) (collectively, the “Wilks”). On December 21, 2021, all of the then-outstanding membership interests in Best Flow and Alpine were contributed to ProFrac LLC in exchange for membership interests in ProFrac LLC.

As more fully described under “Summary—Recent Developments,” on March 4, 2022, ProFrac LLC completed its acquisition of the subsidiaries, business and assets of FTS International, Inc., a Delaware corporation (“FTSI”), in a series of related transactions (together, the “FTSI Acquisition”). You should read “Summary—Recent Developments—FTSI Acquisition” for more information regarding the FTSI Acquisition. Unless otherwise indicated, historical financial and operating information presented as of dates and for periods prior to March 4, 2022 is that of ProFrac Predecessor and does not give effect to the FTSI Acquisition, and historical financial and operating information presented as of dates and for periods on and after March 4, 2022 gives effect to the FTSI Acquisition.

Unless otherwise indicated, references in this prospectus to our financial or operating information on a “pro forma basis” refer to the historical financial or operating information of ProFrac Predecessor, as adjusted to give pro forma effect to the items described in the “ProFrac Predecessor and FTSI Combined Pro Forma” column in “Capitalization,” in the case of statements of operations information, as if they occurred on January 1, 2021 and, in the case of balance sheet information, as if they occurred on December 31, 2021.

Results of interim periods are not indicative of the results expected for a full year or for future periods. Historical financial and operating information is not indicative of the results that may be expected in any future periods. For more information, please see the historical consolidated financial statements and unaudited pro forma condensed financial statements and related notes thereto included elsewhere in this prospectus.

 

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Industry and market data

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications and other published independent sources. Although we believe these third-party sources are reliable as of their respective dates, neither we nor the underwriters have independently verified the accuracy or completeness of this information. Some data is also based on our good faith estimates. The industry in which we operate is subject to a high degree of uncertainty and risk due to a variety of factors, including those described in the section entitled “Risk Factors.” These and other factors could cause results to differ materially from those expressed in these publications.

Trademarks and trade names

We own or have rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. This prospectus may also contain trademarks, service marks and trade names of third parties, which are the property of their respective owners. Our use or display of third parties’ trademarks, service marks, trade names or products in this prospectus is not intended to, and does not imply, a relationship with, or endorsement or sponsorship by us. Solely for convenience, the trademarks, service marks and trade names referred to in this prospectus may appear without the ®, TM or SM symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, our rights or the right of the applicable licensor to these trademarks, service marks and trade names.

 

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Summary

This summary provides a brief overview of information contained elsewhere in this prospectus. This summary does not contain all of the information that you should consider before making an investment decision with respect to our Class A common stock. You should read the entire prospectus carefully, including the financial statements and the notes to those financial statements included in this prospectus. Unless indicated otherwise, the information presented in this prospectus assumes (i) an initial public offering price of $22.50 per share of Class A common stock (the midpoint of the price range set forth on the cover page of this prospectus) and (ii) that the underwriters do not exercise their option to purchase additional shares of Class A common stock. You should read “Risk Factors” for more information about important risks that you should consider carefully before buying our Class A common stock.

Unless the context otherwise requires or as otherwise indicated, references in this prospectus to the “Company,” “we,” “our” and “us,” or like terms, refer to (i) ProFrac and its consolidated subsidiaries, including Best Flow and Alpine and, as of dates and for periods on and after March 4, 2022, the subsidiaries, business and assets we acquired in the FTSI Acquisition, in each case, before the completion of our Corporate Reorganization in connection with this offering and (ii) ProFrac Holding Corp. and its consolidated subsidiaries as of the completion of our Corporate Reorganization and thereafter. See “Corporate Reorganization” below. When we refer to a “fleet” or a “frac fleet,” we are referring to the pumping units, truck tractors, data trucks, storage tanks, chemical additive and hydration units, blenders and other equipment necessary to perform hydraulic fracturing services, including back-up pumping capacity. We have provided definitions for some of the terms we use to describe our business and industry and other terms used in this prospectus in the “Glossary of Selected Terms” beginning on page A-1 of this prospectus.

Overview

We are a growth-oriented, vertically integrated and innovation-driven energy services company providing hydraulic fracturing, completion services and other complementary products and services to leading upstream oil and gas companies engaged in the exploration and production (“E&P”) of North American unconventional oil and natural gas resources. Founded in 2016, ProFrac was built to be the go-to service provider for E&P companies’ most demanding hydraulic fracturing needs. We are focused on employing new technologies to significantly reduce “greenhouse gas” (“GHG”) emissions and increase efficiency in what has historically been an emissions-intensive component of the unconventional E&P development process. We believe the technical and operational capabilities of our fleets ideally position us to capture increased demand resulting from the market recovery and our customers’ shifting preferences favoring the sustainable development of natural resources.

Our operations are primarily focused in the West Texas, East Texas/Louisiana, South Texas, Oklahoma, Uinta and Appalachian regions, where we have cultivated deep and longstanding customer relationships with some of those regions’ most active E&P companies. We operate in three business segments: stimulation services, manufacturing and proppant production. We believe we are the largest privately owned, and second largest overall, provider of hydraulic fracturing services in North America by hydraulic horsepower (“HHP”), with aggregate installed capacity of over 1.7 million HHP across 34 conventional fleets, of which, as of March 31, 2022, 31 were active, reflecting a net installed capacity of approximately 1.5 million HHP across our active fleets. We believe a greater percentage of our conventional fleets prior to the FTSI Acquisition incorporated lower-emission Tier IV diesel engines relative to our peers, making them among the most emissions-friendly and capable in the industry. Further, we believe that because of those fleets’ capabilities and reliability, and our

 

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relentless focus on efficient and environmentally-sound energy service solutions, our high-quality customer base views us as an integral partner in their efforts to improve their environmental, social and governance (“ESG”) profiles without sacrificing service quality.

Our lower-emission conventional hydraulic fracturing fleets have been designed to reduce our customers’ relative emissions footprint while handling the most demanding well completions, which are characterized by higher pumping pressures, higher pumping volumes, longer horizontal wellbores, more frac stages per lateral and increasing amounts of proppant pumped per well. Approximately 90% of our fleets not acquired in the FTSI Acquisition (“Pre-Acquisition Fleets”) are less than six years old, with 60% having Tier IV engines and 49% having dual fuel capabilities as of March 31, 2022. In addition, we have paired these technologies with our proprietary engine standby controllers (“ESCs”) to reduce idle time, which is the time during which an engine generates the highest amount of emissions, by as much as 90%, and reduce fuel consumption and GHG emissions by as much as 24%. In addition, these ESCs are capable of cold starting the engines on our pumping units without the assistance of truck tractors. This technology allows us to significantly decrease the number of truck tractors required for our operations, not only further reducing overall emissions but also eliminating the capital, safety risks and operating and maintenance costs associated with operating the additional truck tractors required for fleets that do not utilize ESCs. On the whole, these cost savings are significant, allowing us to avoid an incremental $15,000 per year in costs associated with each truck tractor eliminated from our operations. Since early 2021, we have installed ESCs in seven fleets, and have reduced our truck tractor count by 125. We continue to install ESCs throughout our fleets, with 141 pumps equipped with ESCs as of March 31, 2022, and anticipate being able to realize total cost savings of approximately $300,000 per year per fleet as a result. When further combined with our real time GHG emissions monitoring, our fleets create additional synergies in efficiency that result in cost savings for our customers. We intend to continue to upgrade and overhaul our other fleets with the goal of having all of our conventional fleets similarly equipped, a process made cheaper by our in-house manufacturing capabilities detailed below. This strategy aligns with our ESG initiative to minimize our carbon footprint as a part of our goal to have all of our conventional fleets equipped with emissions reduction technology. By contrast, many of the fleets we acquired in the FTSI Acquisition are substantially older, are generally less technologically advanced and do not have the same attractive emissions profile as our Pre-Acquisition Fleets. These legacy fleets may require additional maintenance and capital expenditures and may be unable to reduce our customers’ relative emissions footprint or satisfy their ESG objectives. Following the completion of the FTSI Acquisition, approximately 60% of our fleets are less than six years old, with 30% having Tier IV engines and 40% having dual fuel capabilities as of March 31, 2022. After giving effect to our retirement of 650,000 HHP from 11 of FTSI’s older, emissions-intensive fleets acquired in the FTSI Acquisition, 40% of our fleets will have Tier IV engines and 54% of our fleets will have dual fuel capabilities.

In addition to our existing low-emission conventional fleets, we are constructing electric powered hydraulic fracturing fleets equipped with Clean Fleet® technology licensed from U.S. Well Services, Inc. (“USWS”). Under our agreement with USWS, we have acquired 3 licenses and may acquire up to 17 additional licenses (along with certain other rights) to construct in-house new, electric-powered hydraulic fracturing fleets utilizing Clean Fleet® technology. This technology utilizes electric motors powered by lower-cost, lower-emission power solutions, including local utility-sourced line power, or on-site generation from natural gas produced and conditioned in the field, compressed natural gas (“CNG”), liquefied natural gas (“LNG”), hydrogen and/or traditional fuels, if needed. This flexibility in fuel supply can provide our customers with additional tools to meet their emissions and sustainability goals by reducing their reliance on diesel, as well as offer potentially significant fuel cost savings. We believe that our fleets equipped with Clean Fleet® technology will supplement our environmentally advantaged conventional fleets and provide our customers an optimized suite of options to satisfy their ESG objectives while maximizing operating efficiency. We expect to begin deploying the first of these electric-powered hydraulic fracturing fleets in the second quarter of 2022, and we have two more under

 

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construction, which we expect to be ready for deployment during the second half of 2022. We believe that our new electric fleets, together with our existing conventional fleets, which we continue to optimize to incorporate efficiency-enhancing features, place us on the leading edge of the domestic hydraulic fracturing business and position us to maintain a high equipment utilization rate, low emissions and attractive profitability.

Facilitating the advanced technology and operational capability of our equipment is our vertically integrated business model and supply chain management, which allows us to manufacture, assemble, repair and maintain our own fleets and ancillary frac equipment, including power ends, fluid ends, flow iron and monolines. Our vertically integrated business model also allows us to offer customers a suite of ancillary services that enhance the efficiency of the well completion process, including sand, completion chemicals and related equipment.

We operate facilities in Cisco, Aledo and Fort Worth, Texas, including an International Organization for Standardization (“ISO”) 9001 2015 certified OEM manufacturing facility, in which we manufacture and refurbish many of the components used by our fleets, including pumps, fluid ends, power ends, flow iron and other consumables and an engine and transmission rebuild facility that is licensed to provide warranty repairs on our transmissions. These facilities, which have a proven capability to manufacture up to 22 pumps, or 55,000 HHP, per month (including electric fleets) and perform substantially all of the maintenance, repair and servicing of our hydraulic fracturing fleets, provide in-house manufacturing capacity that enables cost-advantaged growth and maintenance.

Vertical integration enables us to realize a lower capital investment and operating expense by capturing the margin of manufacturing and/or maintenance, by recycling and refurbishing older machinery in our fleet, as opposed to disposing of it and by enabling the ongoing improvement of our equipment and processes as part of a continuous research and development cycle. This combination also facilitates our “Acquire, Retire, Replace” approach to growing, maintaining and modernizing our fleets, and helps us mitigate supply chain constraints that have disrupted competitors’ and customers’ operations in the past. For example, as part of the FTSI Acquisition we are implementing our “Acquire, Retire, Replace” strategy by retiring 650,000 HHP of FTSI’s older, emissions-intensive fleets and recycling or refurbishing equipment from such fleets. Our in-house manufacturing capabilities also allow us to rapidly implement new technologies in a cost-effective manner not possible for many of our peers. We believe that as a result of this vertical integration, we are able to achieve conventional Tier IV dual fuel fleet construction costs of $540 per HHP contrasted with an industry cost of up to $861 per HHP, according to Daniel Energy Partners, and an average expected price to build electric fleets, excluding power generation, of $467 per HHP inclusive of licensing costs.

Our manufacturing capabilities and control over the manufacturing process have allowed us to design and build hydraulic fracturing fleets to uniform specifications intended for deployment in resource basins requiring high levels of pressure, flow rate and sand intensity. We believe the standardized, modular configuration of our equipment provides us with several competitive advantages, including reduced repair and maintenance costs, reduced downtime, reduced inventory costs, reduced complexity in our operations, training efficiencies and the ability to redeploy equipment among operating basins. We believe that our uniform fleet specifications along with the ability to more directly control our supply chain and end-of-life management for our equipment differentiates us from competitors who typically purchase such equipment from third party manufacturers and rely on such manufacturers or other third parties for repair and maintenance.

We also provide ancillary products and services, further increasing our value as a business partner to our customers, including frac sand, completion chemicals, frac design and related services, logistics coordination and real time data reporting, such as operational statistics, inventory management, completions updates and emissions monitoring.

Through our recent convertible preferred equity investment in Flotek Industries, Inc. (“Flotek”), we have gained access to a low-cost, long-term supply of a full suite of completion chemicals required by our customers during

 

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the completion process, including Flotek’s proprietary biodegradable complex nano-Fluid® technology, which is more environmentally friendly than commonly used alternatives. For additional information on our investment in Flotek, please see “Summary—Recent Developments—Flotek Investment.”

In addition, to meet our customers’ need for proppant, we operate an approximate three-million-ton-per-year sand mine and processing facility in Kermit, Texas, with 40.7 million tons of proved reserves as of December 31, 2021, which allows us to sell proppant to our customers in West Texas and Southeastern New Mexico. We also recently acquired approximately 6,700 acres near Lamesa, Texas (“West Munger”) that we are developing into an in-basin Permian Basin frac sand resource. We are in the process of installing mining and processing facilities at West Munger which, once operational, will be one of only two sand mines in the Midland Basin. West Munger and the Kermit sand mine are each located within 100 miles of approximately 98% of all horizontal rigs in the Permian Basin, providing us with ready access to potential customers. Our integrated service platform creates operational efficiencies for our customers and allows us to capture a greater portion of their development capital spending, positioning us to maintain high equipment utilization rates, low emissions and attractive profitability.

For the year ended December 31, 2021, ProFrac Predecessor generated net losses of approximately $43.5 million, Adjusted EBITDA of approximately $134.7 million, Adjusted EBITDA less net capital expenditures of approximately $64.8 million and Adjusted EBITDA per fleet of $9.6 million and, on a pro forma basis, generated net losses of approximately $144.6 million, Adjusted EBITDA of approximately $170.3 million, Adjusted EBITDA less net capital expenditures of approximately $59.6 million and Adjusted EBITDA per fleet of $6.4 million. For the definitions of Adjusted EBITDA, Adjusted EBITDA less net capital expenditures and Adjusted EBITDA per fleet and a reconciliation to their most directly comparable financial measures calculated and presented in accordance with generally accepted accounting principles (“GAAP”), please read “—Summary Historical and Pro Forma Financial Data—Non-GAAP Financial Measures.”

Industry trends

Demand for hydraulic fracturing services is primarily driven by the level of drilling and completion activity by E&P companies in the United States. Drilling and completion activity is driven by well profitability and returns, which in turn are influenced by a number of factors, including current domestic and international supply and demand for oil and gas and current and expected future prices for oil and gas, as well as the perceived stability and sustainability of those prices over the longer term.

In 2020, the COVID-19 pandemic and disagreements over production levels among oil producing nations combined to cause unprecedented reductions in global economic activity and significantly reduced the demand for oil and gas. These declines led to a significant dip in commodity prices, with per-barrel prices of West Texas Intermediate (“WTI”) crude oil briefly falling as low as negative $37/Bbl in April of 2020 and averaging $39/Bbl for the full year 2020, versus $57/Bbl for the full year 2019. In response to the unfavorable price environment, U.S. E&P companies dramatically reduced capital spending, oil and gas drilling and completion activity, and thus, demand for hydraulic fracturing services declined significantly in 2020.

In 2021, economic activity rebounded supported by the COVID-19 vaccination program rollouts and the lifting of mobility restrictions, driving the rapid recovery of global demand for oil and gas despite the occurrence of COVID-19 variants. The per-barrel prices of WTI crude oil averaged $68/Bbl for the full year 2021, an increase of 73% year over year.

In 2022, geopolitical tensions in Eastern Europe related to Russia’s invasion of Ukraine have resulted in significant supply disruptions as a broad coalition of countries have responded with sanctions and/or import bans associated with Russian oil and natural gas. This has resulted in significant tightening in the market as reflected by higher commodity prices, with oil and gas prices reaching decade highs. As of March 11, 2022, WTI has averaged $91.60/Bbl in 2022, and the closing price reached as high as $123.70/Bbl on March 8, 2022 following Russia’s invasion of Ukraine. According to the U.S. Energy Information Administration (the “EIA”),

 

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2022 global crude oil and gas demand is forecast to be around 165.5 MMBoe/d, an increase of 7% relative to 2020 global demand. Oil demand is expected to surpass pre-pandemic levels by the second half of 2022. Demand for natural gas is also expected to grow to support the continued industrialization of developing countries over the coming decades. Fundamental trends shaping the energy transition, including the use of natural gas as a transition fuel, are expected to drive gas to continue gaining global energy demand share.

Global Historical and Projected Oil and Gas Demand

 

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Source: EIA International Energy Outlook as of October 6, 2021. Includes global liquids and natural gas demand.

Supported by the backdrop of improved global economic growth, U.S. oil and gas consumption is forecasted to increase 8% from 2020 through 2023, according to EIA. U.S. natural gas demand is expected to increase due to use of natural gas as feedstock in domestic petrochemical projects, the growing exports of LNG to international markets in Europe and Asia, particularly as European countries attempt to reduce their reliance on Russian gas in light of recent geopolitical events, and the addition of gas fired power generation as coal plants are decommissioned.

U.S. Historical and Projected Oil and Gas Demand

 

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Source: EIA Short-Term Energy Outlook as of March 8, 2022 for 2017 to 2023P and EIA Annual Energy Outlook as of March 3, 2022 for 2024P. Includes U.S. liquids and natural gas demand.

Natural gas prices have increased substantially compared to year-end 2020 prices and have also surpassed year-end 2019 (pre-COVID-19) levels. Through March 11, 2022, natural gas prices have averaged approximately $4.03/MMBtu over the last twelve months, reflecting an increase of 76% and 72% relative to the twelve months

 

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from March 11 averages in 2021 and 2020, respectively. Moreover, commodities futures markets as of March 11, 2022 price natural gas contracts at an average of $4.88/MMBtu for the remainder of 2022. Over the longer-term, EIA expects exports and industrial use will continue to drive increased demand for natural gas. If hydrocarbon prices remain at or near current levels, we expect drilling and completion activity to continue to increase, thereby positively impacting demand for our services and improving our revenues and pricing.

With the growth in oil and gas demand and rise in commodity prices, E&P activity has increased significantly across all onshore oil and gas basins in the United States. According to Baker Hughes Company’s (“Baker Hughes”) North American Rig Count reported on March 11, 2022, the number of active U.S. land drilling rigs has increased 68% over the last 12 months to 652 rigs and by 182% since its recent trough of 231 rigs in August 2020. Rig activity in our primary areas of operation (the West Texas, East Texas/Louisiana, South Texas, Oklahoma, Uinta and Appalachian regions) has also increased substantially over that same period.

We believe that the following market dynamics and trends in our industry should benefit our operations and our ability to achieve our business objectives as commodity prices recover:

Increasing frac intensity per working rig.    Techniques used by E&P companies, such as multi-well pad development programs, have led to improved rig efficiencies, resulting in more horizontal wells drilled per rig. Coupled with longer laterals, this trend indicates that demand for well completion services as well as frac spend per rig can be expected to outpace standalone rig growth. The co-location of wells on a single pad also allows for more efficient access to wellbores and sharply reduces the mobilization and de-mobilization time between completion and production service jobs. These efficiencies improve our operating leverage and enable us to more successfully provide our services.

 

Total Well Split by Pad Size

 

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Frac Spend per Rig

 

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Source: Rystad Energy Inc. (“Rystad Energy”) as of February 2022 for total well split by pad size and Spears & Associates Q4 2021 Hydraulic Fracturing and Proppant Market Report for frac sales per rig.

 

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Total U.S. Wells Completed

 

(total wells)

 

Total U.S. Average Proppant Pumped

 

(thousands of lbs. / day)

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Total U.S. Average Well Stimulated Length

 

(feet / day)

 

Total U.S. Average Pumping Intensity

 

(avg. HHP-hrs. / well in thousands)

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Source: Rystad Energy as of February 2022. Metrics are reflective of total U.S. market.

Tightening Frac Sand Market. The increase in demand for frac sand for use in the hydraulic fracturing process has resulted in a significant rise in sand prices as well as constraints on supply availability. According to Lium LLC (“Lium”), total U.S. frac sand demand is expected to increase by 31% in 2022 compared to 2021 and reach 117 million tons, with the Permian expected to account for approximately 57% of the total U.S. demand. Frac sand pricing has surpassed pre-COVID levels, with Permian free on board (“FOB”) mine pricing reaching as high as $60/ton in the spot market in the first quarter of 2022, according to Lium. We believe our recent investment in West Munger and vertically integrated business model position us to capitalize on this increased demand and insulate our operations from rising sand raw material costs and any potential supply chain disruptions.

 

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Permian Frac Sand Demand Forecast

 

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Source: Lium Permian Frac Sand Market Trends as of February 2022. Assumes $85/bbl oil price scenario.

In-Basin Permian Sand Pricing Forecast

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Source: Lium Permian Frac Sand Market Trends as of February 2022.

Investor and regulator focus on ESG.    The energy industry is undergoing a significant change of operating practices with an emphasis on incorporating more environmental and social considerations into operating models. Companies are experiencing increased market pressure to bolster ESG programs, particularly related to climate change and reduction of GHG emissions. As the regulatory environment becomes more stringent, we believe that state and federal governments are likely to implement increased measures to regulate GHG emissions, increasing pressure on E&P companies to decrease their emissions footprint. Additional ESG topics, such as human rights, supply chain management, water usage, natural capital and biodiversity, among others, are also receiving increased attention, and there may be increasing pressure on our customers to take actions to address these topics, as well.

Adoption of dynamic gas blending (“DGB”) and electric fleets.    We believe E&P operators’ focus on improving their emissions profile will accelerate the transition from legacy, emission-heavy Tier II diesel frac fleets to greener Tier IV DGB frac fleets and electric fleets because Tier IV DGB fleets utilize gas, including natural gas, CNG, LNG, pipeline and field gas, as a cheaper, cleaner fuel source. Rystad Energy anticipates that by the end of 2024, approximately 50-60% of active horsepower in North America will be utilizing natural gas capable fleets.

 

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We believe the shift to cleaner natural gas capable fleets positions us well to capture additional market share as the broader industry recovery continues accelerating.

Historical and Projected U.S. Frac Supply by Type

 

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Source: Rystad Energy as of February 2022. Metrics are reflective of total U.S. market.

Obsolescence of significant hydraulic fracturing horsepower in the market.    We believe the U.S. frac market is currently facing a pivotal transition with significant fleet capacity nearing retirement due to obsolescence. We believe that prolonged underinvestment has resulted in an over-supply of legacy fleets and an increasing preference for low-emission fleets is driving an undersupply of more desirable greener frac fleets. Even prior to the COVID-19 induced downturn, substantial legacy capacity had already reached the end of its useful life, according to Rystad Energy. We believe this was further exacerbated by the lack of capital investment by frac operators during the downturn. The majority of frac service providers’ fleets have an average equipment age of more than six years, according to Rystad Energy. We believe that our vertical integration and lower capital cost resulting from our in-house manufacturing of our own frac equipment will benefit our ability to both maintain attractive utilization rates and earn higher returns on invested capital versus other peers that source their new fleets from third parties at higher prices.

U.S. Average Frac Fleet Age

(Number of service providers by average frac equipment age)

 

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Source: Rystad Energy as of March 2022. Metrics are reflective of total U.S. market. Fleet age calculated based on manufacture date for total fleets.

 

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Despite the negative impact to the overall oil and gas industry in 2020, we believe the challenging industry conditions allowed us to strengthen our leadership position by implementing targeted and forward-looking initiatives. We took actions to maintain the ongoing operational integrity of our equipment, further invest in vertical integration of our business, implement back-office optimization projects, successfully complete our in-house research and development of advanced power end and fluid-end designs, and add over 179 dual fuel kits to our Tier IV engines. All of the aforementioned initiatives materially enhanced our company and positioned us to take advantage of expected improving industry conditions.

Competitive strengths

We believe the following characteristics differentiate us from our peers and uniquely position us to execute on our strategy to create value for our stakeholders:

 

 

High performing, technologically advanced fleet focused on cash flow, increased efficiencies and lower emissions.    We believe we are strongly positioned to continue to respond to the increased demand for highly-efficient and environmentally advantaged energy services, which are those that produce fewer negative impacts on the environment than those provided by standard Tier II fleets. We believe our Pre-Acquisition Fleet was the largest fleet of low emissions and technologically advanced conventional frac equipment in the United States, with 60% of that fleet equipped with Tier IV engines and 49% with dual fuel capabilities as of March 23, 2022. While the fleets acquired in the FTSI Acquisition have a more emissions-intensive profile, we have already begun to implement our “Acquire, Retire, Replace” strategy by committing to retire 650,000 HHP of older, emissions-intensive fleets and recycling or refurbishing equipment from such fleets.

We believe our technologically advanced fleets are among the most reliable and best performing in the industry with the capabilities to meet the most demanding pressure and flow rate requirements in the field. For example, we are one of the few energy services companies to install 60-inch pumps in our fleets, providing for significantly higher capacity and capability. The combination of these factors provides us with an ability to operate efficiently in the most demanding environments while helping our customers meet their ESG goals.

Our standardized equipment reduces our downtime, as our mechanics can quickly and efficiently diagnose and repair our equipment, and reduces the amount of inventory we need on hand. We are able to easily shift equipment among operating areas as needed to take advantage of market conditions or to replace temporarily damaged equipment. This flexibility allows us to target customers that are offering higher prices for our services, regardless of the basins in which they operate. Standardized equipment also reduces the complexity of our operations, which lowers our training costs and improves our safety profile. Finally, our standardized, high specification equipment, manufacturing capabilities and direct control over our supply chain lead to lower total cost of ownership, which we believe allows us to both increase our margins and meet increasing demand for efficient, environmentally-advantaged energy services.

To complement our modern and highly efficient conventional fleets, we expect to begin deploying the first of our electric-powered hydraulic fracturing fleets in the second quarter of 2022, and we have two more under construction, which we expect to be ready for deployment during the second half of 2022. By replacing Tier II diesel engines with electric engines, we expect our fleets equipped with Clean Fleet® technology will reduce carbon emissions by up to 33% per fleet annually. These estimates are based on manufacturer specifications for fuel consumption of each engine configuration and hold constant operational factors that influence the

 

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rate of fuel consumption and emissions, such as rate and pressure. This expected reduction is equivalent to a reduction of approximately 1,700 cars on the road per year per fleet based on U.S. Environmental Protection Agency (“EPA”) estimates.

ProFrac Cumulative Pump Configurations & Upgrades by Year:

 

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(1)   Pre-acquisition fleet mix as of March 31, 2022.

 

 

Vertically integrated business model enhances our ability to meet our customers’ needs.    We operate a vertically integrated business model that includes complementary manufacturing and ancillary products and services, including frac sand, completion chemicals, frac design and data reporting services. Our manufacturing capabilities enhance our profitability through reduced capital and maintenance expenditures, and provides a significant advantage in cost savings and supply chain management versus our peers who do not manufacture and rebuild/refurbish their own equipment and components. Furthermore, we have strategically invested in businesses providing ancillary products and services, such as our investments in West Munger, Flotek and FHE USA LLC, a manufacturer of pressure control equipment and service provider based in Fruita, Colorado (“FHE”), which provides us with greater supply chain control and mitigates disruptions that have previously impacted the operations of our competitors and customers. We manufacture and refurbish many of the components used by our fleets, including pumps, fluid–ends, power–ends, certain high–pressure iron and other consumables at our facilities located in Cisco, Aledo and Fort Worth, Texas. We have the proven capability to manufacture up to 22 pumps, or 55,000 HHP per month (including electric fleets) and perform substantially all of the maintenance, repair and servicing of our hydraulic fracturing fleets in-house. We also operate an engine and transmission rebuild facility that is licensed to provide warranty repairs on our transmissions.

 

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“We do the hard jobs.”    Vertical integration of our business enables us to take on premium frac jobs that have more demanding pressure and flow rate requirements that put extra wear and tear on frac equipment and require more frequent equipment rebuilds. We believe many competitors avoid these jobs as they lack the capital or repair capability to sustainably maintain their equipment and generate a reasonable return. At ProFrac, we find such challenging work more economically attractive than less intensive “commodity” work that is easier on equipment because we can be more competitive with higher associated profitability.

 

   

Rapid and cost-effective implementation of new technologies.    Much of our equipment is customized for our operations and built with substantially uniform specifications. With our in-house manufacturing capabilities, we are able to rapidly fabricate, develop and deploy new equipment and rebuild/refurbish existing equipment with minimal reliance on third-party supply chains or paying a premium for bespoke orders or processes. In addition to manufacturing our pumping units, we have the capability to manufacture many of the other components of our fleets such as blenders and hydration units. Our manufacturing capabilities facilitated our development of the Centipede high pressure flow system, which reduces non-productive time by reducing rig up time by up to 50% and iron connections by up to 70%, while also preventing shutdowns. We have also developed proprietary vibration monitoring technology that enables our artificial intelligence-driven predictive pre-failure maintenance, performance reporting and design customizations on core equipment. Finally, our preferred equity investment in FHE provides us with access to innovative technology, including its proprietary wellhead pressure control systems, RigLock and FracLock that enhance well completion efficiency and safety and reduce emissions.

 

   

Advantaged in tight market.    Our vertical integration reduces the risk that we will be unable to source important components, such as fluid-ends, power-ends and other consumable parts and ancillary products and services, such as sand and chemicals. During periods of high demand growth for hydraulic fracturing services, external equipment vendors often report order backlogs of up to nine months, which can lead to increased costs or substantial delays to deploy fleets. The FTSI Acquisition strengthens our in-house repair and manufacturing facilities by increasing our capacity and adding a licensed transmission repair facility. We have historically manufactured all major consumable components and can quickly scale to support all of our fleets at full capacity.

 

   

Insulated from supply chain issues. Our vertical integration on key completion commodities, such as chemicals and sand, mitigate our exposure to price spikes and supply shortages that have negatively impacted the financial results of some of our competitors during the fourth quarter of 2021 and the first quarter of 2022. We have identified sources of pricing and supply chain risk and have made strategic investments to mitigate them, turning potential weaknesses into strengths. For example, we believe the Flotek investment, through which we monetized our procurement demand, demonstrates our commitment to our vertical integration strategy and provides greater control over our supply chain.

 

 

Organizational culture based on world class service, innovation, safety, improving environmental impact and active contributions to our communities.    We believe our corporate culture plays a significant role in our ability to consistently deliver excellent service to our customers, as well as our ability to attract and retain high quality personnel. We encourage innovation throughout our organization and empower our employees to innovate. For example, we maintain an innovation award program for our employees which provides cash incentives for changes to equipment and processes that improve efficiency and safety. Motivated by this program, our employees have developed numerous tools, processes and equipment enhancements that improve our operations, such as a tool for performing maintenance on fluid ends that reduces the time required for a routine maintenance procedure from 45 minutes to 15 minutes, our PadTrac system that performs live job monitoring and a tool for rebuilding butterfly valves that allows this task to be performed by a single technician. We are committed to the safety and wellness of our employees and we actively foster training, advancement and career development. We also seek to actively contribute our time and resources to positively impact the communities in which we work and live.

 

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Loyal and active customers that appreciate our efficiency, suite of services and ability to complete the most difficult and demanding projects.    We have a strong portfolio of active customers that value our modern, technologically advanced equipment and our commitment to a more ESG-conscious service offering. As a part of the FTSI Acquisition, our customer base has expanded and diversified to include some of the larger independent exploration and production companies, in addition to our preexisting customer base consisting of leading private midsize operators. We and FTSI had no customer overlap prior to the FTSI Acquisition, resulting in a further diversified customer base in which, as of March 31, 2022, no single customer contracted more than three of our fleets. Our customers trust us to execute on their most technically demanding operations and value our unique ability to meet their needs with our vertically integrated business model. We believe our operating history combined with our emissions savings equipment and integrated supply chain has us well positioned to serve customers’ needs. While certain of our customers have historically struggled with supply chain disruptions, our business model gives us an opportunity to provide these customers with bundled services, including frac sand, completion chemicals, frac design and related services, logistics and real time data reporting, helping to limit supply chain disruptions. Our track record of consistently providing high-quality, safe and reliable service has enabled us to develop long-term partnerships with our customers, and we expect that our customers will continue to support our growth.

 

 

Strong data and digital capabilities.    Our focus on technology and innovation also underpins our efficiency through real time data analysis of operational statistics, inventory management, completions updates and emissions monitoring. We offer a comprehensive and competitive suite of data and digital solutions such as PadTrac and SOPHIA. PadTrac is a real time data stream that provides pertinent equipment data on location to our operators. SOPHIA is our cloud-based platform that accompanies the ESC and provides visibility into fuel savings and carbon footprint reduction. SOPHIA enhances the credibility, consistency and transparency of carbon footprint quantification by following ISO standards. We believe our digital infrastructure saves time, money, and makes us a more productive and cost effective enterprise.

 

 

Large scale and leading market share across most active major U.S. basins.    We believe we are the largest privately held hydraulic fracturing provider in North America based on HHP. We operate in some of the most active basins in the United States, including the West Texas, East Texas/Louisiana, South Texas, Oklahoma, Uinta and Appalachian regions and our operations have diversified exposure to both natural gas and oil producing areas. This geographic and commodity diversity reduces volatility in our revenue due to regional trends, relative commodity prices, adverse weather and other events. Our large footprint and standardized equipment enables us to rapidly reposition our fleets based on demand trends among different regions and allows us to spread our fixed costs over a greater number of fleets. Our large scale also strengthens our negotiating position with our suppliers and our customers. Additionally, we expect to leverage our strengths to capture market share in these regions in response to customer demand for more efficient and cleaner fleets.

 

 

Experienced management and shareholder team that have driven extreme value creation for stakeholders in past endeavors.    Our senior management team has more than 100 years of relevant experience in hydraulic fracturing and the energy industry. The management team is focused on the operational success of the Company and their interests are aligned with those of investors and customers. Additionally, our principal shareholders, the Wilks, have a proven history of founding and growing pressure pumping companies. Prior to founding ProFrac, the Wilks founded FracTech Holdings, LLC, the predecessor to FTSI in 2000, which they grew into one of the largest North American hydraulic fracturing companies based on HHP before selling their 70% interest in that business in 2011 in a transaction that valued the business at $5 billion. The FTSI Acquisition reunites that business with a management team familiar with FTSI’s personnel, culture and equipment and is

 

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well suited to execute our “Acquire, Retire, Replace” strategy through strategic cannibalization of FTSI’s older fleets. Combined, the Wilks have more than 75 years’ experience in the energy and energy services sectors. Under their leadership, we have grown our hydraulic fracturing business to a total of 34 fleets, as of March 31, 2022, with an aggregate of over 1.7 million HHP and pro forma 2021 revenues exceeding $1.17 billion. Upon completion of this offering, the Wilks will own approximately 84.8% of our voting stock. We believe that their experience will continue to benefit our operations and business. In addition, Lance Turner, FTSI’s former Chief Financial Officer, became our Chief Financial Officer upon the closing of the FTSI Acquisition. We believe Mr. Turner’s previous experience as Chief Financial Officer of FTSI since October 2015 will further streamline our efforts to efficiently integrate the FTSI business and operations into our business.

Business strategies

We intend to achieve our primary business objective of creating value for our stakeholders through the following business strategies:

 

 

Position ourselves as a key partner to our customers in response to increasing focus on environmental sustainability.    As the demand for energy services in the United States recovers from the lows experienced in 2020, we expect demand for our hydraulic fracturing services to continue to grow significantly. In particular, as one of the largest hydraulic fracturing service providers in North America based on HHP, we believe our modern, technologically advanced fleets position us to capitalize on customer mandates for “next generation” frac fleets due to their lower emissions and the economic benefits of fuel cost savings. We also offer our customers a suite of ancillary products and services that we believe is responsive to our customers’ evolving needs, including frac sand, completion chemicals, frac design, manufacturing and related services, logistics and real time data reporting. Rystad Energy estimates that total HHP capacity has declined by approximately 8.8 million HHP as of Q1 2022 from approximately 25 million HHP at the end of 2018, as a result of frac equipment permanently leaving the market due to scrapping, cannibalization and deferred maintenance. In addition, approximately 25% of remaining horsepower is comprised of obsolete or non-operational fleets, according to Rystad Energy. By contrast, we have focused on upgrading and expanding our fleets’ capabilities and investing in ancillary products and services, and have positioned ourselves as ready to respond to our customers’ needs as upstream activity returns and the focus on ESG-sensitive operations grows. Furthermore, our consistently high fleet utilization levels and 24 hours per day, seven days per week operating schedule should result in greater revenue opportunity and enhanced margins as fixed costs are spread over a broader revenue base. We believe that any incremental future fleet additions will benefit from these trends and associated economies of scale.

 

 

Commitment to returns-driven, environmentally-advantaged investments and technology to support further emissions reduction and greater operational efficiency.    We believe demand for lower emissions operations will outpace current supply and lead to further opportunities to deploy new technical solutions to our customers relative to our competition, particularly with natural gas playing an increasingly critical role in the transition away from less clean sources of energy. We have invested in various businesses and technologies that we plan to leverage to strengthen our market position and to better serve our customers as well as share in the fuel savings provided by our investments. For example, in January 2021, we acquired a 75% ownership stake in EKU Power Drives, GMBh (“EKU”), a provider of idle reduction technologies and the manufacturer of our proprietary ESCs. Engines with ESCs will automatically turn off during non-operating time, shutting down the powertrain when it is not pumping and immediately restarting it to full load upon request. This technology reduces the wear and tear on equipment, reduces fuel consumption and eliminates emissions when the engines on our pumping units are automatically turned off and on between stages. A typical frac spread will pump between 14 to 18 hours per day and idle the remaining time. As idle time widely

 

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varies between operating stages, most frac companies leave the engines in idle due to the labor-intensive process associated with using the power take-off on a truck tractor to re-start the engine. Based on our own provision of hydraulic fracturing services, we believe our ESCs eliminate roughly 90% of idle hours and result in substantially lower emissions and fuel costs. This reduction in idle time can reduce carbon dioxide emissions by up to 24% compared to standard operations in which engines generally run continuously during a frac job.

Additionally, we are supplementing our already environmentally-advantaged conventional fleets with electric fleets equipped with Clean Fleet® technology, which will provide customers additional low emission and cost effective solutions. We intend to continue this focus on efficiency and emissions-optimized technology in order to capitalize on the increased demand for higher efficiency and higher performing hydraulic fracturing services. We believe that by pursuing the development of advanced technology in both our conventional fleets and complementary electric-powered fleets, we will be well positioned to capture the increasing demand for highly capable and environmentally-advantaged energy services with which operators may satisfy their ESG imperatives.

We recently invested in West Munger, Flotek and FHE to enhance our access to products and services necessary during the well completion process in order to mitigate supply chain disruptions and improve our operational efficiencies. Flotek is a market leader in environmentally friendly and biodegradable chemical technologies; FHE is a pioneer in high pressure flow control equipment that is safer and more efficient than legacy industry processes; and West Munger will provide access to a geographically advantaged source of frac sand.

 

 

Pursue accretive mix of organic growth and strategic consolidation.    We plan to continue to grow our operations and fleets in response to increased customer demand as well as selectively evaluate potential strategic acquisitions that increase our scale and capabilities and diversify our operations. In response to supply constraints for frac sand, among other factors, we acquired Alpine and West Munger, which we expect to reduce our exposure to supply chain risks and increase our proppant production capacity. We are continuing to evaluate vertical integration of in-basin proppant and logistics opportunities in West Texas and other regions. Similarly, we anticipate that our acquisitions of Best and investment in FHE will bolster our in-house manufacturing capabilities and will provide access to innovative technology. We believe opportunities exist to acquire older generation diesel frac fleets at attractive prices and use our in-house manufacturing capabilities to upgrade and maintain them, thus extending their useful life and maximizing their cash flow, after which they can be replaced with cutting edge dual fuel or electric technology as part of our “Acquire, Retire, Replace” strategy. We have already begun implementing this strategy with the fleets acquired in the FTSI Acquisition by retiring 650,000 HHP of older FTSI fleets and recycling or refurbishing equipment from such fleets as a source of spare parts and components in our vertically integrated manufacturing segment in connection with selectively upgrading legacy equipment to Tier IV dual fuel engines, increasing efficiency and sustainability. We estimate that FTSI’s existing fleets can be converted to dual fuel capability at a cost of approximately $2.0 million per fleet. The resulting displacement of older fleets should yield significant improvements in emissions, operating efficiency, safety and profitability and provide a source of spare parts and components that can reduce our maintenance capital expenditures. Our vertically integrated business model and in house manufacturing enables faster integration of assets we may acquire and allows us to more economically and efficiently cannibalize, refurbish, and redeploy equipment. Additionally, we expect that our technology and focus on lower emission fleets will promote growth and attract new customers focused on reducing their emissions profiles.

 

 

Continued focus on safe, efficient and reliable operations.    We are an industry leader with a proven track record in safety with a Total Reportable Incident Rate (“TRIR”) of 0.42 for the year ended December 31, 2021,

 

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including our manufacturing division, compared to the industry average of 0.70, according to the International Association of Oil & Gas Producers (“IOGP”). We prioritize safety in our equipment through mechanisms like AFEX fire control, which is installed on all of our field equipment and is designed to suppress fires immediately. We believe our excellent safety record is partly attributable to the standardization of our equipment, which makes it easier for mechanics and equipment operators to identify and diagnose problems with equipment before a safety hazard arises. Our fleets are also standardized to use Centipede mono-line, which has fewer iron connections on site and allows for a safer and quicker rig up versus traditional flow iron assemblies. Our streamlined, innovative equipment enables safer operations and time savings, mitigation of inefficiencies from shutdowns and improvements relative to the amount of horsepower required to put down hole. Additionally, our standardized equipment and in-house manufacturing capability allows us to rapidly assess operations as well as test new equipment while also reducing the complexity of our operations and lowering our training costs.

 

 

Focus on generating superior returns while maintaining a conservative balance sheet and financial policies.    We plan to maintain a conservative balance sheet following this offering, which will allow us to better react to potential changes in industry and market conditions and opportunistically grow our business. We had $301.3 million of net senior debt, defined as total senior debt of $306.7 million less $5.4 million of cash and equivalents, as of December 31, 2021, and we intend to use a portion of the proceeds from this offering to offer to retire at least $100 million of our senior debt. On a pro forma basis, our net debt as of December 31, 2021 to Adjusted EBITDA for the year ended December 31, 2021 was 1.77. Our 2022 capital expenditure budget, excluding acquisitions, is estimated to be in a range between $240 million and $290 million. We have budgeted approximately $65 million to $70 million to construct three electric-powered fleets. We are fully committed to building the three electric-powered fleets and have several customers interested in contracting these fleets. We intend to align fleet construction and other growth capital expenditures with visible customer demand, by strategically deploying new equipment in response to inbound customer requests and industry trends. Also included in our 2022 capital expenditure budget is $25 million to $30 million to construct the West Munger sand mine. The remainder of our 2022 capital expenditure budget, excluding acquisitions, will be used to fund maintenance capital expenditures, estimated to be $2.75 million to $3.0 million per fleet per year, and other growth initiatives such as upgrading Tier II fleets to Tier IV dual fuel fleets. We continually evaluate our capital expenditures and the amount that we ultimately spend will depend on a number of factors, including customer demand for new fleets and expected industry activity levels. We believe we will be able to fund our 2022 capital program from cash flows from operations. We are disciplined about deploying growth capital to our business, and expect investments in new fleets to have a simple payback of 2.0 years or fewer before investing. As a result of this approach, we believe that we operate one of the most profitable frac businesses and that our strategies and competitive advantages have contributed to our strong relative financial performance, as demonstrated by our history of positive EBITDA generation despite recent market volatility. Our vertical integration of key supply chains enables consistent cost management, low capital intensity and high conversion of EBITDA to cash flow, which we believe will help us deliver shareholder returns across market cycles, while maintaining a conservative balance sheet.

Recent developments

Preliminary Estimate of Selected First Quarter 2022 Financial Results

The following preliminary financial information presents estimated results for (a) ProFrac Predecessor for the three months ended March 31, 2022, which includes the results of operations of FTS International, Inc. from March 4, 2022, the closing date of the FTSI Acquisition, and (b) FTS International, Inc. on a standalone basis for

 

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the period from January 1, 2022 to February 28, 2022 prior to the consummation of the FTSI Acquisition. This presentation includes ranges for these preliminary financial results because closing procedures for the three months ended March 31, 2022 are not yet complete. These estimated ranges are preliminary and unaudited and are thus inherently uncertain and subject to change. In addition, ProFrac Predecessor’s preliminary financial information for the three months ended March 31, 2022 will not be comparable with our prior historical financial information, which does not include the results of FTSI.

As customary quarterly close and review procedures as of and for the three months ended March 31, 2022 are completed, there can be no assurance that the final results for this period will not differ from the estimates presented below. During the course of the preparation of our consolidated financial statements and related notes as of and for the three months ended March 31, 2022, we may identify items that could cause ProFrac Predecessor’s final reported results to be materially different from the preliminary financial estimates presented herein. For a discussion of important factors that could cause actual results to differ from our preliminary estimates, see “Risk Factors,” “Cautionary Statement Regarding Forward-Looking Statements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

These estimates should not be viewed as a substitute for full interim financial statements prepared in accordance with GAAP. In addition, these preliminary estimates are for informational purposes only and are not necessarily indicative of the results to be achieved as of any future date or for any future period. The consolidated financial statements and related notes of ProFrac Predecessor as of and for the three months ended March 31, 2022 are not expected to be filed with the SEC until after this offering is completed. The preliminary estimated unaudited financial results included in this prospectus have been prepared by, and are the responsibility of, our management. Our independent registered public accounting firm, Grant Thornton LLP, has not audited, reviewed, compiled or performed any procedures with respect to the preliminary financial results. Accordingly, Grant Thornton LLP does not express an opinion or any other form of assurance with respect thereto.

Set forth below is a range of estimates of our preliminary actual results for (a) ProFrac Predecessor for the three months ended March 31, 2022, and (b) FTS International, Inc. on a standalone basis for the period from January 1, 2022 to February 28, 2022:

 

     
     ProFrac Predecessor      FTS International,
Inc.
 
     Three Months Ended
March 31, 2022
     January 1, 2022 to
February 28, 2022
 
      Low      High      Low      High  

Total revenues

   $ 343.6      $ 351.1      $ 71.6      $ 79.1  

Total cost of revenues, exclusive of depreciation, depletion and amortization

     231.2        234.7        57.2        60.7  

Depreciation, depletion and amortization

     37.9        39.9        6.1        8.1  

Average active fleets

     21.7        21.7        14.0        14.0  

 

 

A material uplift in activity sequentially and ahead-of-schedule pricing improvements in the first quarter of 2022 produced better-than-expected results. In particular, as a result of geopolitical tensions in Eastern Europe related to Russia’s invasion of Ukraine, the current shortage of other sources of energy, and the economic growth associated with what appears to be a global emergence from the pandemic, the demand for and price of oil and gas increased significantly in the first quarter of 2022 as compared to the first quarter of 2021. These factors resulted in an increase in the prices of oil and natural gas not seen since mid-2014, which increased both the utilization of our fleets and the prices we were able to charge for our services. While we experienced modest increases in expenses attributable to inflation and supply-demand imbalances in the supply chain, increasing utilization and pricing allowed us to maintain and increase our margins.

 

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We have experienced strong pricing improvement in the first quarter of 2022 and expect that improvement to continue into the second quarter of 2022.

The FTSI fleets have historically been less profitable on a per fleet basis than the legacy ProFrac fleets. We estimate the per fleet profitability of the legacy ProFrac fleets was approximately 10% higher than the preliminary ProFrac Predecessor first quarter per fleet results (which include the results of the FTSI fleets from March 4, 2022 to the end of the period) and the run rate of the legacy ProFrac fleets is approximately 20% higher than the preliminary ProFrac Predecessor first quarter results.

In the weeks following the FTSI Acquisition, we have been able to increase the prices of the fleets acquired in the FTSI Acquisition. We estimate the FTSI fleets generated approximately 20% higher revenue per fleet in March 2022 as compared to the first two months of 2022, and we expect those same fleets to generate approximately 20% higher revenue per fleet in April 2022 as compared to March 2022. With a relatively stable cost structure, we expect these pricing increases to lead to a significant increase in the profitability of the FTSI fleets. After giving effect to these net pricing impacts, we believe the FTSI fleets will have per fleet profitability similar to the legacy ProFrac fleets.

FTSI Acquisition

On March 4, 2022, ProFrac LLC acquired FTSI for a purchase price of approximately $407.5 million, consisting of cash consideration of $334.6 million and certain equity interests in ProFrac LLC of $72.9 million. FTSI was one of the largest providers of hydraulic fracturing services in North America, with 1.3 million HHP as of December 31, 2021. FTSI averaged 13 active fleets (including 7 dual fuel fleets) in the fourth quarter of 2021, with operations in the Permian Basin, Eagle Ford Shale, Midcontinent, Haynesville Shale and Uinta Basin. FTSI activated its first Tier 4 DGB fleet in January 2022 to bring its active fleet count to 14. Following the FTSI Acquisition, we are in the process of retiring the remaining 11 idle fleets, and we expect to use those fleets in our maintenance operations. In calendar year 2021, FTSI had increased its average pumping hours per day by over 75% since the first quarter of 2018 and its fleets pumped, on average, more days per month than any prior year in its existence. FTSI enjoyed an industry-leading maintenance capex per fleet of $2.6 million during 2021, which is approximately 40% to 50% below the estimated average per-fleet maintenance capex of its peers. FTSI recently reached an agreement to build and deploy a new fleet outfitted with Caterpillar Inc.’s Tier IV DGB engines to a large, independent exploration and production company on a dedicated basis. The agreement offers pricing and utilization levels that we believe will allow us to recoup over two-thirds of the associated capital investment over an initial term of 18 months. We believe the FTSI Acquisition could result in potential synergies, in the form of annual cost reductions, of approximately $55 million (consisting of annual reductions in cost of sales of approximately $35 million, maintenance capex of approximately $10 million and selling, general and administrative expenses of approximately $10 million). We calculated these potential synergies based on the differences between FTSI’s historical third party costs associated with equipment repairs and rebuilds, and our historical costs of conducting equivalent repairs and rebuilds in-house.

In connection with the completion of the FTSI Acquisition, FTSI conveyed to Wilks Development, LLC, an affiliate of ProFrac LLC, substantially all of FTSI’s owned real property, consisting primarily of FTSI’s hydraulic fracturing equipment manufacturing facilities, in exchange for cash consideration of approximately $44.4 million (the “FTSI Sale Leaseback”). We will lease such real property from Wilks Development, LLC in exchange for aggregate monthly lease payments of $51.6 million through March 2032. See “Certain Relationships and Related Party Transactions—Wilks Development Lease Agreement.”

 

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We funded the approximately $334.6 million cash consideration for the FTSI Acquisition, and our associated expenses, with a combination of borrowings under the New Term Loan Credit Facility (as defined herein) and the New ABL Credit Facility (as defined herein), ProFrac LLC’s cash on hand, proceeds from the FTSI Sale Leaseback and approximately $44.0 million in subordinated debt financing from THRC Holdings, LP, a Texas limited partnership that is controlled by Dan Wilks (“THRC Holdings”) and Equify Financial, LLC, an affiliate of the Wilks. In addition, THRC Holdings, which owned approximately 19.5% of FTSI, agreed to retain that interest in FTSI in lieu of receiving cash pursuant to the FTSI Merger Agreement. Immediately following the closing of the cash acquisition pursuant to the FTSI Merger Agreement, ProFrac LLC distributed the 80.5% of the FTSI equity it acquired in such merger to Farris Wilks and THRC Holdings in a manner that resulted in each of them owning 50% of FTSI (the “FTSI Distribution”), with THRC Holdings receiving a smaller share of the FTSI Distribution and instead retaining certain preferred equity in ProFrac LLC in lieu of its redemption in connection with such distribution (such ProFrac LLC equity, the “THRC FTSI Related Equity”). Immediately following the FTSI Distribution, FTSI contributed all of its subsidiaries, business and assets to ProFrac LLC in exchange for common equity interests in ProFrac LLC with a value equal to the net fair market value of such subsidiaries, business and assets. As a result, the former subsidiaries, business and assets of FTSI, other than those subject to the FTSI Sale Leaseback, are wholly owned by us.

New Term Loan Credit Facility

On March 4, 2022, ProFrac LLC, ProFrac Holdings II, LLC, as borrower (“ProFrac II LLC” or, in such capacity, the “Term Loan Borrower”), and certain of ProFrac II LLC’s wholly owned subsidiaries as obligors, entered into a senior secured term loan credit agreement (the “New Term Loan Credit Facility”), with Piper Sandler Finance LLC, as administrative agent and collateral agent (the “Term Loan Agent”), and the lenders party thereto. The New Term Loan Credit Facility provides for a term loan in an aggregate principal amount of $450.0 million. As of April 30, 2022, the Term Loan Borrower had approximately $450.0 million outstanding under the New Term Loan Credit Facility. The proceeds from borrowings under the New Term Loan Credit Facility were used to fund a portion of the purchase price in the FTSI Acquisition and associated expenses and to repay in full and terminate certain outstanding indebtedness and credit facilities of ProFrac LLC and its subsidiaries.

New ABL Credit Facility

On March 4, 2022, ProFrac LLC, ProFrac II LLC, as borrower (in such capacity, the “ABL Borrower”), and certain of the ABL Borrower’s wholly owned subsidiaries as obligors, entered into a senior secured asset-based revolving credit agreement (as amended, the “New ABL Credit Facility”), with JPMorgan Chase Bank N.A., as administrative agent and collateral agent (the “ABL Agent”), and the lenders party thereto. The New ABL Credit Facility provides for an asset-based revolving credit facility with lender commitments of $200 million. As of April 30, 2022, the maximum availability under the New ABL Credit Facility as of that date was the aggregate lender commitments of $200.0 million. In addition, on that date, there were $110.7 million of borrowings outstanding and $9.2 million of letters of credit outstanding, resulting in approximately $80.1 million of remaining availability. Such borrowings were incurred primarily to finance the FTSI Acquisition and refinance borrowings outstanding under ProFrac LLC’s Old ABL Credit Facility, which borrowings were incurred primarily to fund working capital.

FHE Investment

In February 2022, we acquired the preferred equity in FHE for $45.95 million. We believe FHE’s products and services, which include proprietary completion equipment and related services, will improve the efficiency and safety of our frac services, while allowing us to expand our manufacturing capabilities and suite of completion services. Currently,

 

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FHE has an installed base of approximately 175 RigLock systems, one of their flagship products, servicing a number of market-leading E&P and oilfield services operators.

Flotek Investment

On February 2, 2022, we entered into an agreement with Flotek, a technology-driven, specialty green chemicals and logistics provider, pursuant to which Flotek will provide full downhole chemistry solutions for a minimum of ten hydraulic fleets or 33% of our Pre-Acquisition Fleets for three years starting on April 1, 2022, at a price of cost plus 7% (“Flotek Supply Agreement”). In exchange for entry into the Flotek Supply Agreement, we received $10 million in initial principal amount of notes that are convertible into Flotek common stock and acquired an additional $10 million in principal amount of such notes in a related private offering transaction. Our equity ownership in Flotek on a fully diluted basis as a result of this investment is greater than 16%. In addition, we are permitted to designate up to two new directors to Flotek’s board of directors.

On February 16, 2022, we and Flotek agreed to amend the Flotek Supply Agreement to increase the term to ten years and increase the scope to 30 fleets. In exchange for our entry into the amendment to the Flotek Supply Agreement (the “Flotek Supply Agreement Amendment”), Flotek agreed to issue us $50 million in initial principal amount of notes that will be convertible into Flotek common stock. The Flotek Supply Agreement Amendment and issuance to us of additional Flotek convertible notes are conditioned upon customary closing conditions including the approval of Flotek’s shareholders. Assuming the satisfaction of such closing conditions, including the approval of Flotek’s shareholders, our equity investment in Flotek on a fully diluted basis after the consummation of these transactions will be between 40% and 50%, and we will be permitted to designate two additional directors, or up to four new directors to Flotek’s board of directors.

The Flotek Supply Agreement Amendment includes a minimum annual volume commitment whereby we will be obligated to pay Flotek liquidated damages equal to 25% of the shortfall for such year, should we fail to meet the minimum purchase amount. We estimate that the current supply agreement would lead to a shortfall payment of approximately $40 million per year if we do not purchase any chemicals from Flotek. We currently expect to be able to fulfill the minimum annual volume commitment on the greater of 10 fleets or 33% of our Pre-Acquisition Fleets pursuant to the Flotek Supply Agreement Amendment.

The notes issued to ProFrac accrue paid-in-kind interest at a rate of 10% per annum, have a maturity of one year, and convert into common stock of Flotek (a) at the holder’s option at any time prior to maturity, at a price of $1.088125 per share, (b) at Flotek’s option, if the volume-weighted average trading price of Flotek’s common stock equals or exceeds $2.50 for 20 trading days during a 30 consecutive trading day period, or (c) at maturity, at a price of $0.8705 (the “Convertible Notes”).

We believe the Flotek Supply Agreement Amendment and the Convertible Notes demonstrate our commitment to our vertical integration strategy and provide greater control over our supply chain, monetize procurement demand and provide a hedge against price increases in completion chemicals by securing a fixed price contract for such chemicals.

West Munger Acquisition

In December 2021, we acquired approximately 6,700 acres near Lamesa, Texas, which we refer to as West Munger, that we are developing into an in-basin Permian Basin frac sand resource. We acquired West Munger for aggregate consideration equal to (at the option of the West Munger sellers) $30.0 million in cash or, upon the closing of this offering, approximately 2,235,600 shares of our Class A common stock, based upon a per share price of $22.50 (the “West Munger Acquisition”). We are in the process of installing mining and processing

 

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facilities at the site that would permit us to mine and process two million tons of sand per year and we expect such facilities to be operational in the third quarter of 2022. The acquisition increases our proppant production capacity while mitigating supply chain constraints and operational disruptions.

Electric fleets

We are party to an agreement with USWS that permits us to purchase up to 20 licenses for its Clean Fleet® electric frac, or “efrac” technology. We have purchased three licenses, and we expect to begin deploying the first of these electric-powered hydraulic fracturing fleets in the second quarter of 2022, and we have two more under construction, which we expect to be ready for deployment during the second half of 2022. These fleets significantly reduce emissions, sound pollution and fuel consumption when compared to Tier II diesel fleets without sacrificing strong operational performance. We intend to align additional fleet construction with visible customer demand and to use our vertically integrated manufacturing facility to build the units, leading to what we believe will be the lowest capital cost electric frac technology in the market.

Principal shareholders

The Wilks are our principal shareholders. Prior to founding ProFrac in 2016, the Wilks founded the predecessor to FTSI in 2000, which they grew into one of the largest North American hydraulic fracturing companies based on HHP before selling their interest in that business in 2011. Combined, Dan Wilks and Farris Wilks have more than 75 years’ experience in the energy and energy services sectors.

Upon completion of this offering, the Wilks will beneficially own approximately 49.6% of our Class A common stock and approximately 96.5% of our Class B common stock, collectively representing approximately 84.8% of the voting power of the Company. In addition, THRC Holdings and the Farris and Jo Ann Wilks 2022 Family Trust have indicated that they may collectively purchase in this offering an aggregate of up to $117.0 million, or 5,200,000 shares (based on the midpoint of the price range set forth above), of our Class A common stock at the price to the public. Assuming THRC Holdings and the Farris and Jo Ann Wilks 2022 Family Trust purchase an aggregate of 5,200,000 shares of Class A common stock, the Wilks will beneficially own approximately 64.5% of our Class A common stock and approximately 96.5% of our Class B Common stock, collectively representing approximately 88.5% of the voting power of the Company. The underwriters will not receive any underwriting discounts or commissions on any shares sold to THRC Holdings or the Farris and Jo Ann Wilks 2022 Family Trust. We are also a party to certain agreements with other businesses owned by or affiliated with the Wilks. For a description of these agreements, please read “Certain Relationships and Related Party Transactions.”

Our history and Corporate Reorganization

We were incorporated as a Delaware corporation on August 17, 2021. Following this offering and the related transactions, ProFrac Holding Corp. will be a holding company whose only material asset will consist of ProFrac LLC Units (as defined below). ProFrac LLC owns, directly or indirectly, all of the outstanding equity interests in the subsidiaries through which we operate our assets. After the consummation of the Corporate Reorganization, ProFrac Holding Corp. will be the sole managing member of ProFrac LLC and will be responsible for all operational, management and administrative decisions relating to ProFrac LLC’s business and will consolidate the financial results of ProFrac LLC and its subsidiaries.

In connection with the offering:

 

 

all of the membership interests in ProFrac LLC held by the then-existing owners of ProFrac LLC (including the THRC FTSI Related Equity) will be converted into a single class of common units in ProFrac LLC (“ProFrac LLC

 

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Units”, and any holder of ProFrac LLC Units other than ProFrac Holding Corp. and its wholly-owned subsidiaries, the “ProFrac LLC Unit Holders”);

 

 

ProFrac Holding Corp. will issue to each ProFrac LLC Unit Holder a number of shares of Class B common stock equal to the number of ProFrac LLC Units held by such ProFrac LLC Unit Holder following this offering in exchange for a cash payment equal to the par value of such shares;

 

 

ProFrac Holding Corp. will issue 16,000,000 shares of Class A common stock to purchasers in this offering in exchange for the proceeds of this offering; and

 

 

ProFrac Holding Corp. will use a portion of the proceeds of this offering to purchase the THRC FTSI Related Equity from THRC Holdings, and we will contribute the remaining net proceeds of this offering to ProFrac LLC in exchange for a number of ProFrac LLC Units such that ProFrac Holding Corp. will directly and indirectly hold a total number of ProFrac LLC Units equal to the number of shares of Class A common stock outstanding following this offering.

After giving effect to these transactions and the offering contemplated by this prospectus, ProFrac Holding Corp. will directly and indirectly own an approximate 25.0% interest in ProFrac LLC (or 26.2% if the underwriters’ option to purchase additional shares is exercised in full), and the ProFrac LLC Unit Holders will own an approximate 75.0% interest in ProFrac LLC (or 73.8% if the underwriters’ option to purchase additional shares is exercised in full) and all of our Class B common stock. Please see “—Principal Shareholders.”

Each share of Class B common stock has no economic rights but entitles its holder to one vote on all matters to be voted on by stockholders generally. Holders of Class A common stock and Class B common stock will vote together as a single class on all matters presented to our stockholders for their vote or approval, except as otherwise required by applicable law or by our amended and restated certificate of incorporation. We do not intend to list the Class B common stock on any exchange.

Following this offering, under the Third Amended and Restated Limited Liability Company Agreement of ProFrac LLC (the “ProFrac LLC Agreement”), each ProFrac LLC Unit Holder will, subject to certain limitations, have the right, which we refer to as the “Redemption Right,” to cause ProFrac LLC to acquire all or a portion of its ProFrac LLC Units for, at ProFrac LLC’s election, (i) shares of our Class A common stock at a redemption ratio of one share of Class A common stock for each ProFrac LLC Unit redeemed, subject to conversion rate adjustments for stock splits, stock dividends and reclassifications and other similar transactions, or (ii) an equivalent amount of cash. The independent members of our board of directors will determine whether to pay cash in lieu of the issuance of shares of Class A common stock based on facts in existence at the time of the decision, which we expect would include the relative value of the Class A common stock (including trading prices for the Class A common stock at the time), the cash purchase price, the availability of other sources of liquidity (such as an issuance of stock) to acquire the ProFrac LLC Units and alternative uses for such cash. Alternatively, upon the exercise of the Redemption Right, ProFrac Holding Corp. (instead of ProFrac LLC) will have the right, which we refer to as the “Call Right,” to, for administrative convenience, acquire each tendered ProFrac LLC Unit directly from the redeeming ProFrac LLC Unit Holder for, at its election, (x) one share of Class A common stock, subject to conversion rate adjustments for stock splits, stock dividends and reclassifications and other similar transactions, or (y) an equivalent amount of cash. In addition, ProFrac Holding Corp. will have the right to require, upon the acquisition by ProFrac Holding Corp. of substantially all of the ProFrac LLC Units or upon a change of control of ProFrac Holding Corp., each ProFrac LLC Unit Holder to exercise its Redemption Right with respect to some or all of such unitholder’s ProFrac LLC Units. In connection with any redemption of ProFrac LLC Units pursuant to the Redemption Right or acquisition of ProFrac LLC Units

 

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pursuant to the Call Right, a corresponding number of shares of Class B common stock held by the relevant ProFrac LLC Unit Holder will be cancelled. See “Certain Relationships and Related Party Transactions—ProFrac LLC Agreement.”

ProFrac Holding Corp.’s acquisition (or deemed acquisition for U.S. federal income tax purposes) of ProFrac LLC Units in connection with this offering or pursuant to an exercise of the Redemption Right or the Call Right is expected to result in adjustments to the tax basis of the tangible and intangible assets of ProFrac LLC, and such adjustments will be allocated to ProFrac Holding Corp. These adjustments would not have been available to ProFrac Holding Corp. absent its acquisition or deemed acquisition of ProFrac LLC Units and are expected to reduce the amount of cash tax that ProFrac Holding Corp. would otherwise be required to pay in the future.

ProFrac Holding Corp. will enter into the Tax Receivable Agreement with certain of the ProFrac LLC Unit Holders (each such person or its permitted transferees, a “TRA Holder”, and collectively, the “TRA Holders”) at the closing of this offering. This agreement will generally provide for the payment by ProFrac Holding Corp. to each TRA Holder of 85% of the net cash savings, if any, in U.S. federal, state and local income tax and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that ProFrac Holding Corp. actually realizes (or is deemed to realize in certain circumstances) in periods after this offering as a result of (i) certain increases in tax basis that occur as a result of ProFrac Holding Corp.’s acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such TRA Holder’s ProFrac LLC Units in connection with this offering or pursuant to the exercise of the Redemption Right or the Call Right and (ii) imputed interest deemed to be paid by ProFrac Holding Corp. as a result of, and additional tax basis arising from, any payments ProFrac Holding Corp. makes under the Tax Receivable Agreement. ProFrac Holding Corp. will be dependent on ProFrac LLC to make distributions to ProFrac Holding Corp. in an amount sufficient to cover ProFrac Holding Corp.’s obligations under the Tax Receivable Agreement.

We will retain the benefit of the remaining 15% of any actual net cash tax savings.

For additional information regarding the Tax Receivable Agreement, see “Risk Factors—Risks Related to this Offering and Our Class A Common Stock” and “Certain Relationships and Related Party Transactions—Tax Receivable Agreement.”

 

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The following diagram indicates our simplified ownership structure immediately following this offering and the transactions related thereto (assuming that the underwriters’ option to purchase additional shares is not exercised). In addition, the following diagram does not give effect to the purchase of any shares by THRC Holdings and the Farris and Jo An Wilks 2022 Family Trust as discussed on the cover page of this prospectus.

 

 

LOGO

Summary risk factors

Investing in our Class A common stock involves risks. You should carefully read the section of this prospectus entitled “Risk Factors” beginning on page 36 and the other information in this prospectus for an explanation of these risks before investing in our Class A common stock. In particular, the following considerations may offset our competitive strengths or have a negative effect on our strategy or operating activities, which could cause a decrease in the price of our Class A common stock and a loss of all or part of your investment.

Risks related to our business

 

 

Our business and financial performance depends on the oil and natural gas industry and particularly on the level of capital spending and E&P activity within the United States and in the basins in which we operate.

 

 

The COVID-19 pandemic reduced demand for our services and could, in the future, have a material adverse effect on our operations, business and financial results.

 

 

The cyclical nature of the oil and natural gas industry may cause our operating results to fluctuate.

 

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The political environment in oil and natural gas producing regions, including uncertainty or instability resulting from civil disorder, terrorism or war, such as the recent conflict between Russia and Ukraine, may materially affect our operating results.

 

 

We face significant competition that may cause us to lose market share.

 

 

Our business depends upon our ability to obtain specialized equipment, parts and key raw materials from third-party suppliers, and we may be vulnerable to delayed deliveries and future price increases.

 

 

We currently rely on a limited number of suppliers for major equipment to build new electric-powered hydraulic fracturing fleets utilizing Clean Fleet® technology, and our reliance on these vendors exposes us to risks including price and timing of delivery.

 

 

Reliance upon a few large customers may adversely affect our revenue and operating results.

 

 

We are exposed to counterparty credit risk. Nonpayment and nonperformance by our customers, suppliers or vendors could adversely impact our operations, cash flows and financial condition.

 

 

Oil and natural gas companies’ operations using hydraulic fracturing are substantially dependent on the availability of water. Restrictions on the ability to obtain water for E&P activities and the disposal of flowback and produced water may impact their operations and have a corresponding adverse effect on our business, results of operations and financial condition.

 

 

We rely on a few key employees whose absence or loss could adversely affect our business.

 

 

A negative shift in investor sentiment of the oil and gas industry has had and could in the future have adverse effects on our customers’ operations and ability to raise debt and equity capital.

 

 

Our operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could limit our ability to grow.

 

 

Concerns over general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.

 

 

Our indebtedness and liquidity needs could restrict our operations and make us more vulnerable to adverse economic conditions.

 

 

Restrictions in our debt agreements and any future financing agreements may limit our ability to finance future operations, meet capital needs or capitalize on potential acquisitions and other business opportunities.

 

 

Our operations are subject to unforeseen interruptions and hazards inherent in the oil and natural gas industry, for which we may not be adequately insured and which could cause us to lose customers and substantial revenue.

 

 

Inaccuracies in our estimates of mineral reserves and resource deposits, or deficiencies in our title to those deposits, could result in our inability to mine the deposits or require us to pay higher than expected costs.

 

 

Increasing trucking regulations may increase our costs and negatively impact our results of operations.

 

 

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. If we are unable to fully protect our intellectual property rights, or if we are adversely affected by disputes regarding intellectual property rights of third parties, we may suffer a loss in our competitive advantage or market share.

 

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Following the FTSI Acquisition, our fleet includes substantial legacy capacity that may require increased levels of maintenance and capital expenditures to be maintained in good operating condition, is less efficient than our Pre-Acquisition Fleets, and may be subject to a higher likelihood of mechanical failure, an inability to economically return to service or requirement to be scrapped. If we are unable to manage retiring some portion of our fleet efficiently, or if we are unable meet the changing needs of our customers, our results will deteriorate and our financial position and cash flows could be materially adversely affected.

Risks related to environmental and regulatory matters

 

 

Our operations and the operations of our customers are subject to environmental, health and safety laws and regulations, and future compliance, claims, and liabilities relating to such matters may have a material adverse effect on our results of operations, financial position or cash flows.

 

 

Our operations, and those of our customers, are subject to a series of risks arising from climate change.

 

 

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews and investment practices for such activities may serve to limit future oil and natural gas E&P activities and could have a material adverse effect on our results of operations and business.

 

 

Conservation measures, commercial development and technological advances could reduce demand for oil and natural gas and our services.

 

 

Additional restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct completion activities.

Risks related to this offering and our Class A common stock

 

 

ProFrac Holding Corp. is a holding company. ProFrac Holding Corp.’s only material asset after completion of this offering will be its equity interest in ProFrac LLC, and ProFrac Holding Corp. will accordingly be dependent upon distributions from ProFrac LLC to pay taxes, make payments under the Tax Receivable Agreement and cover its corporate and other overhead expenses.

 

 

Conflicts of interest could arise in the future between us, on the one hand, and Dan Wilks and Farris Wilks and entities owned by or affiliated with them, on the other hand, concerning, among other things, business transactions, potential competitive business activities or business opportunities.

 

 

The requirements of being a public company, including compliance with the reporting requirements of the Exchange Act and the requirements of Sarbanes-Oxley, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

 

 

The Wilks have the ability to direct the voting of a majority of our voting stock, and their interests may conflict with those of our other stockholders.

 

 

A significant reduction by Dan Wilks and Farris Wilks of their ownership interests in us could adversely affect us.

 

 

In certain cases, payments under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits, if any, ProFrac Holding Corp. realizes in respect of the tax attributes subject to the Tax Receivable Agreement.

 

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We expect to be a “controlled company” within the meaning of the Nasdaq rules and, as a result, will qualify for and intend to rely on exemptions from certain corporate governance requirements.

Principal executive offices and internet address

Our principal executive offices are located at 333 Shops Boulevard, Suite 301, Willow Park, Texas 76087, and our telephone number is (254) 776-3722. Following the closing of this offering, our website will be located at http://www.profrac.com. We expect to make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission (“SEC”) available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

Emerging growth company status

As a company with less than $1.07 billion in revenue during our last fiscal year, we qualify as an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). As an emerging growth company, we may, for up to five years, take advantage of specified exemptions from reporting and other regulatory requirements that are otherwise applicable generally to public companies. These exemptions include:

 

 

the presentation of only two years of audited financial statements and only two years of related Management’s Discussion and Analysis of Financial Condition and Results of Operations in this prospectus;

 

 

deferral of the auditor attestation requirement on the effectiveness of our system of internal control over financial reporting;

 

 

exemption from the adoption of new or revised financial accounting standards until they would apply to private companies;

 

 

exemption from compliance with any new requirements adopted by the Public Company Accounting Oversight Board requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; and

 

 

reduced disclosure about executive compensation arrangements.

In addition, Section 107 of the JOBS Act also provides that an emerging growth company can use the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933, as amended (the “Securities Act”) for complying with new or revised accounting standards. This permits an emerging growth company to delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We are choosing to take advantage of this extended transition period and, as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for private companies.

We may take advantage of these provisions until we are no longer an emerging growth company, which will occur on the earliest of (i) the last day of the fiscal year following the fifth anniversary of this offering, (ii) the last day of the fiscal year in which we have more than $1.07 billion in annual revenue which, as a result of the FTSI Acquisition, we expect may occur as of December 31, 2022, (iii) the date on which we issue more than

 

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$1 billion of non-convertible debt over a three-year period and (iv) the date on which we are deemed to be a “large accelerated filer,” as defined in Rule 12b-2 promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”).

Controlled company status

Because the Wilks will initially own 17,359,338 shares of Class A common stock and 101,586,572 ProFrac LLC Units (and an equal number of shares of Class B common stock), representing approximately 84.8% of the voting power of the Company following the completion of this offering, we expect to be a controlled company as of the completion of the offering under the Sarbanes-Oxley Act of 2002 (“Sarbanes-Oxley”) and rules of Nasdaq. A controlled company is not required to have a majority of independent directors or to maintain an independent compensation or nominating and governance committee. As a controlled company, we will remain subject to rules of Sarbanes-Oxley that require us to have an audit committee composed entirely of independent directors. Under these rules, we must have at least one independent director on our audit committee by the date our Class A common stock is listed on Nasdaq, at least two independent directors on our audit committee within 90 days of the listing date, and at least three independent directors on our audit committee within one year of the listing date. We expect to have independent directors upon the closing of this offering.

If at any time we cease to be a controlled company, we will take all action necessary to comply with Sarbanes-Oxley and rules of Nasdaq, including by appointing a majority of independent directors to our board of directors and ensuring we have a compensation committee and nominating and governance committee composed of independent directors, subject to a permitted “phase-in” period. See “Management—Status as a Controlled Company.”

 

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The offering

 

Issuer

ProFrac Holding Corp.

 

Class A common stock offered by us

16,000,000 shares.

 

Option to purchase additional shares

We have granted the underwriters a 30-day option to purchase up to an aggregate of 2,400,000 additional shares of our Class A common stock to the extent the underwriters sell more than 16,000,000 shares of Class A common stock in this offering.

 

Class A common stock outstanding after this offering

34,991,326 shares (or 37,391,326 shares if the underwriters exercise in full their option to purchase additional shares).

 

Class B common stock outstanding immediately after this offering

105,244,274 shares or one share for each ProFrac LLC Unit held by the ProFrac LLC Unit Holders immediately following this offering. Shares of Class B common stock are non-economic and are not entitled to receive dividends. In connection with any redemption of ProFrac LLC Units pursuant to the Redemption Right or acquisition of ProFrac LLC Units pursuant to the Call Right, a corresponding number of shares of Class B common stock will be cancelled.

 

Voting power of Class A common stock after giving effect to this offering

25.0% (or 100.0% if all outstanding ProFrac LLC Units held by the ProFrac LLC Unit Holders were redeemed for newly issued shares of Class A common stock on a one-for-one basis).

 

Voting power of Class B common stock after giving effect to this offering

75.0% (or 0.0% if all outstanding ProFrac LLC Units held by the ProFrac LLC Unit Holders were redeemed for newly issued shares of Class A common stock on a one-for-one basis). Upon completion of this offering, the ProFrac LLC Unit Holders will initially own, in the aggregate, 105,244,274 shares of Class B common stock, representing approximately 75.0% of the voting power of the Company.

 

Voting rights

Each share of our Class A common stock entitles its holder to one vote on all matters to be voted on by stockholders generally. Each share of our Class B common stock entitles its holder to one vote on all matters to be voted on by stockholders generally. Holders of our Class A common stock and Class B common stock vote together as a single class on all matters presented to our stockholders for their vote or approval, except as otherwise required by applicable law or by our amended and restated certificate of incorporation. See “Description of Capital Stock.”

 

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Use of proceeds

We expect to receive approximately $334.6 million of net proceeds (assuming the midpoint of the price range set forth on the cover of this prospectus) from the sale of Class A common stock in this offering, after deducting underwriting discounts and commissions and estimated offering expenses. Each $1.00 increase (decrease) in the public offering price would increase (decrease) our net proceeds by approximately $15.0 million.

 

  We intend to use $172.2 million of such net proceeds to make an offer to repay outstanding borrowings under the New Term Loan Credit Facility (which each lender thereunder may accept or reject in its sole discretion) and use the remaining net proceeds to repay amounts outstanding under the Backstop Note (as defined below) in the amount of $22.0 million and to purchase the THRC FTSI Related Equity from THRC Holdings in the amount of $72.9 million (the “THRC Equity Purchase”). Any net proceeds in excess of these amounts will be used as described in “Use of Proceeds.” Please read “Use of Proceeds.”

 

Dividend policy

We do not anticipate paying any cash dividends on our Class A common stock. In addition, our existing debt agreements place, and we expect our future debt agreements will place, certain restrictions on our ability to pay cash dividends. Please read “Dividend Policy.”

 

Redemption Rights of ProFrac LLC Unit Holders

Under the ProFrac LLC Agreement, each ProFrac LLC Unit Holder will, subject to certain limitations, have the right, pursuant to the Redemption Right, to cause ProFrac LLC to acquire all or a portion of its ProFrac LLC Units for, at ProFrac LLC’s election, (i) shares of our Class A common stock at a redemption ratio of one share of Class A common stock for each ProFrac LLC Unit redeemed, subject to conversion rate adjustments for stock splits, stock dividends and reclassifications and other similar transactions, or (ii) an equivalent amount of cash. Alternatively, upon the exercise of the Redemption Right, ProFrac Holding Corp. (instead of ProFrac LLC) will have the right, pursuant to the Call Right, to acquire each tendered ProFrac LLC Unit directly from the redeeming ProFrac LLC Unit Holder for, at its election, (x) one share of Class A common stock, subject to conversion rate adjustments for stock splits, stock dividends and reclassifications and other similar transactions, or (y) an equivalent amount of cash. In connection with any redemption of ProFrac LLC Units pursuant to the Redemption Right or acquisition of ProFrac LLC Units pursuant to the Call Right, a corresponding number of shares of Class B common stock held by the relevant ProFrac LLC Unit Holder will be cancelled. See “Certain Relationships and Related Party Transactions—ProFrac LLC Agreement.”

 

Directed share program

At our request, the underwriters have reserved up to 5% of the Class A common stock being offered by this prospectus for sale, at the initial public offering price, to our directors, executive officers, employees and business associates. The sales will be made by the underwriters through a directed share program. We do not know if these persons will choose to purchase all or any portion of these reserved shares, but any purchases they do make will reduce the number of

 

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shares available to the general public. Please read “Underwriting—Directed Share Program.”

 

Listing and trading symbol

We have applied to list our Class A common stock on Nasdaq under the symbol “PFHC.”

 

Risk factors

You should carefully read and consider the information set forth under the heading “Risk Factors” and all other information set forth in this prospectus before deciding to invest in our Class A common stock.

 

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Summary historical and pro forma financial data

The following table presents summary historical consolidated financial data of ProFrac Predecessor and the unaudited pro forma financial data of ProFrac Holding Corp. as of the dates and for the periods indicated. The summary historical consolidated financial data as of and for the years ended December 31, 2021 and 2020 is derived from the audited financial statements appearing elsewhere in this prospectus. The unaudited pro forma financial data was derived from the unaudited pro forma financial statements included elsewhere in this prospectus. Historical results are not necessarily indicative of future results.

The summary unaudited pro forma statement of operations and balance sheet data as of and for the year ended December 31, 2021 have been prepared to give pro forma effect to (i) the expansion of ProFrac LLC’s term loan credit facility (the “Old Term Loan Credit Facility”) and related purchase of all the series A-1 and series B-1 preferred units in Basin Production and Completion LLC (“BPC” and, such repurchases collectively, the “BPC Acquisition”), (ii) the entry into the New Term Loan Credit Facility and the application of borrowings thereunder to fund a portion of the purchase price in the FTSI Acquisition and associated expenses and to repay in full the Old Term Loan Credit Facility, (iii) the issuance of subordinated debt to THRC Holdings and Equify Financial (“Equify”), the proceeds of which were used to fund a portion of the purchase price in the FTSI Acquisition, (iv) the completion of the FTSI Acquisition, (v) the Corporate Reorganization described under “Corporate Reorganization” and (vi) this offering and the application of the net proceeds therefrom as described in “Use of Proceeds,” in the case of statements of operations information, as if they had occurred on January 1, 2021 and, in the case of balance sheet information, as if they occurred on December 31, 2021.

This information is subject to and gives effect to the assumptions and adjustments described in the notes accompanying the unaudited pro forma financial statements included elsewhere in this prospectus. The unaudited pro forma financial data is presented for informational purposes only, should not be considered indicative of actual results of operations that would have been achieved had such transactions been consummated on the dates indicated and does not purport to be indicative of statements of financial position or results of operations as of any future date or for any future period.

The summary historical consolidated and combined and unaudited pro forma financial data presented below should be read in conjunction with “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements of ProFrac Predecessor and the related notes and the pro forma financial statements of ProFrac Holding Corp. and the related notes and other financial data included elsewhere in this prospectus. Among other things, the historical and pro forma financial statements include more detailed information regarding the basis of presentation for the information in the following table.

 

       
    ProFrac
Predecessor Historical
    ProFrac
Predecessor
and FTSI
Combined
Pro Forma
    ProFrac
Holding
Corporation
Pro Forma
 
    Year ended
December 31,
    Year ended
December 31,
    Year ended
December 31,
 
     2021     2020     2021     2021  

Statement of Operations Data:

       

Total revenues

  $ 768,353     $ 547,679     $ 1,173,603     $ 1,173,603  

Total cost of revenues, exclusive of depreciation, depletion and amortization

    570,122       432,570       886,869       886,869  

Depreciation, depletion and amortization

    140,687       150,662       223,218       223,218  

Loss on disposal of assets, net

    9,777       8,447       11,972       11,972  

Selling, general and administrative

    65,592       51,014       123,192       123,192  

Interest expense, net

    25,788       23,276       51,405       33,282  

 

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    ProFrac
Predecessor Historical
    ProFrac
Predecessor
and FTSI
Combined
Pro Forma
    ProFrac
Holding
Corporation
Pro Forma
 
    Year ended
December 31,
    Year ended
December 31,
    Year ended
December 31,
 
     2021     2020     2021     2021  

Reorganization items, net

                894       894  

Other expense (income)

    111       (324     20,727       31,080  

Income tax (benefit) provision

    (186     582       (116     (116
 

 

 

   

 

 

   

 

 

   

 

 

 

Net loss

    (43,538     (118,548     (144,558 )       (136,788

Net loss attributable to noncontrolling interest

    (1,118     (1,143     (1,118     (102,936
 

 

 

   

 

 

   

 

 

   

 

 

 

Net loss attributable to ProFrac Predecessor

  $ (42,420   $ (117,405   $ (143,440   $ (33,852

Pro Forma Per share information:

       

Net loss per common share:

       

Basic

        $ (0.97

Diluted

        $ (0.97

Weighted average common share outstanding:

       

Basic

          34,992  

Diluted

          34,992  

Balance Sheet Data (as of end of period):

       

Cash and equivalents

  $ 5,376     $ 2,952     $ 59,030     $ 60,085  

Property, plant and equipment, net

  $ 363,687     $ 429,684     $ 602,795     $ 602,795  

Total assets

  $ 664,570     $ 577,277     $ 1,151,338     $ 1,150,411  

 

 

 

 

   

 

 

   

 

 

   

 

 

 

Total Long-term debt

  $ 269,773     $ 260,229     $ 598,478     $ 347,161  

Total equity

  $ 148,110     $ 176,812     $ 213,237     $ (1,874,369

Cash Flow Statement Data:

       

Net cash provided by operating activities

  $ 43,942     $ 45,054      

Net cash used in investing activities

  $ (78,383   $ (44,617    

Net cash provided by (used in) financing activities

  $ 36,865     $ (15,322    

Other Data:

       

Adjusted EBITDA(1)

  $ 134,688     $ 72,797     $ 170,264     $ 170,264  

Adjusted EBITDA less net capital expenditures(1)

  $ 64,841     $ 29,440     $ 59,617     $ 59,617  

Capital expenditures

  $ 87,400     $ 48,037     $ 131,300     $ 131,300  

 

 

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)   For the definitions of Adjusted EBITDA and Adjusted EBITDA less net capital expenditures and a reconciliation to their most directly comparable financial measure calculated and presented in accordance with GAAP, please read “—Non-GAAP Financial Measures.”

Non-GAAP financial measures

Adjusted EBITDA, Adjusted EBITDA less net capital expenditures and Adjusted EBITDA per fleet

Adjusted EBITDA, Adjusted EBITDA less net capital expenditures and Adjusted EBITDA per fleet are non-GAAP financial measures and should not be considered as substitutes for net income, net loss, operating loss or any other performance measure derived in accordance with GAAP or as an alternative to net cash provided by operating activities as a measure of our profitability or liquidity. Adjusted EBITDA, Adjusted EBITDA less net capital expenditures and Adjusted EBITDA per fleet are supplemental measures utilized by our management and other users of our financial statements such as investors, commercial banks, research analysts and others, to assess our financial performance because they allow us to compare our operating performance on a consistent basis across periods by removing the effects of our capital structure (such as varying levels of interest expense), asset base (such as depreciation and amortization) and items outside the control of our management team (such as income tax rates).

We view Adjusted EBITDA, Adjusted EBITDA less net capital expenditures and Adjusted EBITDA per fleet as important indicators of performance. We define Adjusted EBITDA as our net income (loss), before (i) interest expense, net, (ii) income tax provision, (iii) depreciation, depletion and amortization, (iv) loss on disposal of

 

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assets and (v) other unusual or non-recurring charges, such as costs related to our initial public offering, non-recurring supply commitment charges, certain bad debt expense and gain on extinguishment of debt. We define Adjusted EBITDA less net capital expenditures as Adjusted EBITDA less net capital expenditures plus cash proceeds from sales of assets. We define Adjusted EBITDA per fleet for a particular period as Adjusted EBITDA calculated as a daily average of active fleets during the period.

We believe that our presentation of Adjusted EBITDA, Adjusted EBITDA less net capital expenditures and Adjusted EBITDA per fleet will provide useful information to investors in assessing our financial condition and results of operations. In particular, we believe Adjusted EBITDA per fleet allows investors to compare the performance of our fleets across comparable periods and against the fleets of our competitors who may have different capital structures, which may make a fleet-for-fleet comparison more difficult. Net income (loss) is the GAAP measure most directly comparable to Adjusted EBITDA and Adjusted EBITDA less net capital expenditures, and net income (loss) per fleet is the GAAP measure most directly comparable to Adjusted EBITDA per fleet. Adjusted EBITDA and Adjusted EBITDA less net capital expenditures should not be considered as an alternative to net income (loss), and Adjusted EBITDA per fleet should not be considered as an alternative to net income (loss) per fleet. Adjusted EBITDA, Adjusted EBITDA less net capital expenditures and Adjusted EBITDA per fleet have important limitations as analytical tools because they exclude some but not all items that affect the most directly comparable GAAP financial measure. Adjusted EBITDA less net capital expenditures is not necessarily indicative of cash available for discretionary expenditures. You should not consider Adjusted EBITDA, Adjusted EBITDA less net capital expenditures or Adjusted EBITDA per fleet in isolation or as a substitute for an analysis of our results as reported under GAAP. Because Adjusted EBITDA, Adjusted EBITDA less net capital expenditures and Adjusted EBITDA per fleet may be defined differently by other companies in our industry, our definition of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

Reconciliation of net loss to Adjusted EBITDA, Adjusted EBITDA less net capital expenditures and Adjusted EBITDA per fleet

 

       
    ProFrac
Predecessor Historical
    ProFrac
Predecessor
and FTSI
Combined
Pro Forma
    ProFrac
Holding
Corporation
Pro Forma
 
    Year ended
December 31,
    Year ended
December 31,
    Year ended
December 31,
 
     2021     2020    

2021

    2021  

Net loss

  $ (43,538   $ (118,548   $ (144,558   $ (136,788

Interest expense, net

    25,788       23,276       51,405       33,282  

Income tax provision (benefit)

    (186     582       (116     (116

Depreciation, depletion and amortization

    140,687       150,662       223,218       223,218  

Loss on disposal of assets, net

    9,777       8,447       11,972       11,972  

Loss on extinguishment of debt

    515             7,935       18,288  

Bad debt expense, net of recoveries

    (1,164     2,778       (1,012     (1,012

Severance charges

    500             500       500  

Reorganization costs

    2,060             2,954       2,954  

Supply commitment charges

          5,600              

Equity method loss

                13,196       13,196  

Loss on foreign currency transactions

    249             249       249  

Impairments and other charges

                4,521       4,521  
 

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

  $ 134,688     $ 72,797     $ 170,264       $170,264  

Capital expenditures

    (87,400     (48,037     (131,300     (131,300

Cash proceeds from sales of assets

    17,553       4,680       20,653       20,653  
 

 

 

   

 

 

   

 

 

   

 

 

 

Net capital expenditures

    (69,847     (43,357     (110,647     (110,647
 

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA less net capital expenditures

  $ 64,841     $ 29,440     $ 59,617       $59,617  
 

 

 

   

 

 

   

 

 

   

 

 

 

Active fleets

    14       11       26.75       26.75  

Adjusted EBITDA per fleet

  $ 9,621     $ 6,618     $ 6,365       $6,365  

Net loss per fleet

  $ (3,110   $ (10,777   $ (5,404)       $(5,114)  

 

 

 

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Cautionary statement regarding forward-looking statements

This prospectus contains forward-looking statements. Statements that are predictive in nature, that depend upon or refer to future events or conditions or that include the words “may,” “could,” “plan,” “project,” “budget,” “predict,” “pursue,” “target,” “seek,” “objective,” “believe,” “expect,” “anticipate,” “intend,” “estimate,” and other expressions that are predictions of or indicate future events and trends and that do not relate to historical matters identify forward-looking statements. Our forward-looking statements include statements about our business strategy, our industry, our future profitability, our expected capital expenditures and the impact of such expenditures on our performance, the costs of being a publicly traded corporation and our capital programs.

A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

 

 

uncertainty regarding the timing, pace and extent of an economic recovery in the United States and elsewhere, which in turn will likely affect demand for crude oil and natural gas and therefore the demand for our services;

 

 

the level of production of crude oil, natural gas and other hydrocarbons and the resultant market prices of crude oil, natural gas, natural gas liquids and other hydrocarbons;

 

 

the severity and duration of world health events, including the outbreak of the novel coronavirus (“COVID-19”) pandemic, related economic repercussions and the resulting severe disruption in the oil and gas industry and negative impact on demand for oil and gas, which has and may continue to negatively impact our business;

 

 

a further decline or future decline in domestic spending by the onshore oil and natural gas industry;

 

 

actions by members of the Organization of Petroleum Exporting Counties, Russia and other oil-producing countries (“OPEC+”) with respect to oil production levels and announcements of potential changes in such levels;

 

 

the political environment in oil and natural gas producing regions, including uncertainty or instability resulting from civil disorder, terrorism or war, such as the recent conflict between Russia and Ukraine, which may negatively impact our operating results;

 

 

changes in general economic and geopolitical conditions;

 

 

competitive conditions in our industry;

 

 

changes in the long-term supply of and demand for oil and natural gas;

 

 

actions taken by our customers, competitors and third-party operators;

 

 

a decline demand for proppant;

 

 

our ability to obtain permits, approvals and authorizations from governmental and third parties, and the effects of or changes to U.S. government regulation;

 

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changes in the availability and cost of capital;

 

 

our ability to successfully implement our business plan;

 

 

large or multiple customer defaults, including defaults resulting from actual or potential insolvencies;

 

 

the effects of consolidation on our customers or competitors;

 

 

the price and availability of debt and equity financing (including changes in interest rates);

 

 

our ability to complete growth projects on time and on budget;

 

 

our ability to integrate and realize the benefits expected from the FTSI Acquisition including any related synergies;

 

 

introduction of new drilling or completion techniques, or services using new technologies subject to patent or other intellectual property protections;

 

 

operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;

 

 

acts of terrorism, war or political or civil unrest in the United States or elsewhere;

 

 

loss or corruption of our information or a cyberattack on our computer systems;

 

 

the price and availability of alternative fuels and energy sources;

 

 

federal, state and local regulation of hydraulic fracturing and other oilfield service activities, as well as E&P activities, including public pressure on governmental bodies and regulatory agencies to regulate our industry;

 

 

the availability of water resources, suitable proppant and chemicals in sufficient quantities for use in hydraulic fracturing fluids;

 

 

the effects of existing and future laws and governmental regulations (or the interpretation thereof) on us and our customers;

 

 

the effects of future litigation; and

 

 

other factors discussed in this prospectus.

You should not place undue reliance on our forward-looking statements. Although forward-looking statements reflect our good faith beliefs at the time they are made, forward-looking statements involve known and unknown risks, uncertainties and other factors, including the factors described under “Risk Factors,” which may cause our actual results, performance or achievements to differ materially from anticipated future results, performance or achievements expressed or implied by such forward-looking statements. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events, changed circumstances or otherwise, unless required by law. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

 

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Risk factors

Investing in our Class A common stock involves risks. You should carefully consider the risks described below with all of the other information included in this prospectus before deciding to invest in our Class A common stock. If any of the following risks were to occur, our business, financial condition, results of operations and cash flows could be materially adversely affected. In that case, the trading price of our Class A common stock could decline and you could lose all or part of your investment. 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.

Risks related to our business

Our business and financial performance depends on the oil and natural gas industry and particularly on the level of capital spending and E&P activity within the United States and in the basins in which we operate, and a decline in prices for oil and natural gas may have an adverse effect on our revenue, cash flows, profitability and growth.

Demand for most of our services depends substantially on the level of capital expenditures in the United States by companies in the oil and natural gas industry. As a result, our operations are dependent on the levels of capital spending and activity in oil and gas exploration, development and production. A prolonged reduction in oil and gas prices would generally depress the level of oil and natural gas exploration, development, production, and well completion activity and would result in a corresponding decline in the demand for the hydraulic fracturing services that we provide. The significant decline in oil and natural gas prices that occurred in 2020 caused a reduction in our customers’ spending and associated drilling and completion activities, which had an adverse effect on our revenue. While oil and natural gas prices have since increased, should prices again decline, similar declines in our customers’ spending would have an adverse effect on our revenue. In addition, a worsening of these conditions may result in a material adverse impact on certain of our customers’ liquidity and financial position resulting in further spending reductions, delays in the collection of amounts owing to us and similar impacts.

Many factors over which we have no control affect the supply of and demand for, and our customers’ willingness to explore, develop and produce oil and natural gas, and therefore, influence prices for our services, including:

 

 

the U.S. and non-U.S. supply of, and demand for, oil and natural gas;

 

 

the level of prices, and expectations about future prices, of oil and natural gas;

 

 

the level of global oil and natural gas E&P;

 

 

the cost of exploring for, developing, producing and delivering oil and natural gas;

 

 

the supply of and demand for drilling and hydraulic fracturing equipment;

 

 

global or national health concerns, including health epidemics such as the ongoing COVID-19 pandemic;

 

 

the expected decline rates of current production;

 

 

inability to acquire or maintain necessary permits or mining or water rights;

 

 

the price and quantity of foreign imports;

 

 

political and economic conditions in oil and natural gas producing countries and regions, including the United States, the Middle East, Africa, South America and Russia;

 

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actions by the members of OPEC+ and other oil-producing countries with respect to oil production levels and announcements of potential changes in such levels;

 

 

speculative trading in crude oil and natural gas derivative contracts;

 

 

the level of consumer product demand;

 

 

the discovery rates of new oil and natural gas reserves;

 

 

the availability of water resources, suitable proppant and chemical additives in sufficient quantities for use in hydraulic fracturing fluids;

 

 

contractions in the credit market;

 

 

the strength or weakness of the U.S. dollar;

 

 

available pipeline and other transportation capacity;

 

 

the levels of oil and natural gas storage;

 

 

adverse weather conditions and other natural disasters;

 

 

U.S. and non-U.S. tax policy;

 

 

U.S. and non-U.S. governmental approvals and regulatory requirements and conditions;

 

 

the continued threat of terrorism and the impact of military and other action, including military action in the Middle East;

 

 

technical advances affecting energy consumption;

 

 

the proximity and capacity of oil and natural gas pipelines and other transportation facilities;

 

 

the price and availability of alternative fuels and energy sources;

 

 

uncertainty in capital commodities markets and the ability of oil and natural gas producers to raise equity capital and debt financing;

 

 

merger and divestiture activity among oil and natural gas producers;

 

 

cyclical/seasonal business and dependence upon spending of our customers;

 

 

competition among oilfield service and equipment providers;

 

 

changes in transportation regulations that result in increased costs or administrative burdens; and

 

 

overall domestic and global economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. Such a decline would have a material adverse effect on our business, results of operation and financial condition.

The COVID-19 pandemic reduced demand for our services and could, in the future, have a material adverse effect on our operations, business and financial results.

We face risks related to public health crises, including the COVID-19 pandemic. The effects of the COVID-19 pandemic, including travel bans, prohibitions on group events and gatherings, shutdowns of certain businesses,

 

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curfews, shelter-in-place orders and recommendations to practice social distancing in addition to other actions taken by both businesses and governments, resulted in a significant and swift reduction in international and U.S. economic activity. The collapse in the demand for oil caused by this unprecedented global health and economic crisis contributed to the significant decrease in crude oil prices in 2020 and adversely impacted the demand for our services and could, in the future, have a material adverse effect on our operations, business and financial results.

Since the beginning of 2021, the distribution of COVID-19 vaccines progressed and many government-imposed restrictions were relaxed or rescinded. However, we continue to monitor the effects of the pandemic on our customers, operations, and employees. These effects have included, and may continue to include, adverse revenue and net income effects, financial health of our customers and therefore their ability to drill and complete wells or pay for services provided, financial health of our suppliers and therefore their ability to deliver necessary goods and services, disruptions to our operations, and ultimately the financial health and results of the Company.

The extent to which our operating and financial results are affected by COVID-19 will depend on various factors and consequences beyond our control, such as the emergence of more contagious and harmful variants of the COVID-19 virus, the duration and scope of the pandemic, additional actions by businesses and governments in response to the pandemic, and the speed and effectiveness of responses to combat the virus. COVID-19, and the volatile regional and global economic conditions stemming from the pandemic, could also aggravate the other risk factors that we identify herein. While the effects of the COVID-19 pandemic have lessened recently in the United States, we cannot predict the duration or future effects of the pandemic, or more contagious and harmful variants of the COVID-19 virus, and such effects may materially adversely affect our operating and financial results in a manner that is not currently known to us or that we do not currently consider to present significant risks to our operations.

The cyclical nature of the oil and natural gas industry may cause our operating results to fluctuate.

We derive our revenues from companies in the oil and natural gas E&P industry, a historically cyclical industry with levels of activity that are significantly affected by the levels and volatility of oil and natural gas prices. We have experienced, and may in the future experience, significant fluctuations in operating results as a result of the reactions of our customers to changes in oil and natural gas prices. For example, prolonged low commodity prices experienced by the oil and natural gas industry during 2015, 2016 and recently in 2020, combined with adverse changes in the capital and credit markets, caused many E&P companies to reduce their capital budgets and drilling activity. This resulted in a significant decline in demand for oilfield services and adversely impacted the prices oilfield services companies could charge for their services. In addition, a majority of the service revenue we earn is based upon a charge for a relatively short period of time (for example, a day, a week or a month) for the actual period of time the service is provided to our customers. By contracting services on a short-term basis, we are exposed to the risks of a rapid reduction in market prices and utilization and resulting volatility in our revenues.

The ongoing military action between Russia and Ukraine could adversely affect our business, financial condition and results of operations.

On February 24, 2022, Russian military forces commenced a military operation in Ukraine, and sustained conflict and disruption in the region is likely. Although the length, impact and outcome of the ongoing military conflict in Ukraine is highly unpredictable, this conflict could lead to significant market and other disruptions, including significant volatility in commodity prices and supply of energy resources, instability in financial markets, supply chain interruptions, political and social instability, changes in consumer or purchaser preferences as well as increase in cyberattacks and espionage.

 

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Russia’s recognition of two separatist republics in the Donetsk and Luhansk regions of Ukraine and subsequent military action against Ukraine have led to an unprecedented expansion of sanction programs imposed by the United States, the European Union, the United Kingdom, Canada, Switzerland, Japan and other countries against Russia, Belarus, the Crimea Region of Ukraine, the so-called Donetsk People’s Republic and the so-called Luhansk People’s Republic, including, among others:

 

 

blocking sanctions against some of the largest state-owned and private Russian financial institutions (and their subsequent removal from the Society for Worldwide Interbank Financial Telecommunication (“SWIFT”) payment system) and certain Russian businesses, some of which have significant financial and trade ties to the European Union;

 

 

blocking sanctions against Russian and Belarusian individuals, including the Russian President, other politicians and those with government connections or involved in Russian military activities; and

 

 

blocking of Russia’s foreign currency reserves as well as expansion of sectoral sanctions and export and trade restrictions, limitations on investments and access to capital markets and bans on various Russian imports.

For further details on sanctions, see also “—Our business may be affected by sanctions, export controls and similar measures targeting Russia, as well as other responses to Russia’s military action in Ukraine.” The situation is rapidly evolving as a result of the conflict in Ukraine, and the United States, the European Union, the United Kingdom and other countries may implement additional sanctions, export controls or other measures against Russia, Belarus and other countries, regions, officials, individuals or industries in the respective territories. Such sanctions and other measures, as well as the existing and potential further responses from Russia or other countries to such sanctions, tensions and military actions, could adversely affect the global economy and financial markets and could adversely affect our business, financial condition and results of operations. Our manufacturing operations would be potentially vulnerable to interruptions in the supply of certain materials and metals, such as nickel, which are incorporated into raw materials we obtain from suppliers that we use in our manufacturing processes.

Our business may be affected by sanctions, export controls and similar measures targeting Russia, as well as other responses to Russia’s military action in Ukraine.

As a result of Russia’s military action in Ukraine, governmental authorities in the United States, the European Union and the United Kingdom, among others, launched an expansion of coordinated sanctions and export control measures, including:

 

 

blocking sanctions on some of the largest state-owned and private Russian financial institutions (and their subsequent removal from SWIFT);

 

 

blocking sanctions against Russian and Belarusian individuals, including the Russian President, other politicians and those with government connections or involved in Russian military activities;

 

 

blocking sanctions against certain Russian businessmen and their businesses, some of which have significant financial and trade ties to the European Union;

 

 

blocking of Russia’s foreign currency reserves and prohibition on secondary trading in Russian sovereign debt and certain transactions with the Russian Central Bank, National Wealth Fund and the Ministry of Finance of the Russian Federation;

 

 

expansion of sectoral sanctions in various sectors of the Russian and Belarusian economies and the defense sector;

 

 

United Kingdom sanctions introducing restrictions on providing loans to, and dealing in securities issued by, persons connected with Russia;

 

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restrictions on access to the financial and capital markets in the European Union, as well as prohibitions on aircraft leasing operations;

 

 

sanctions prohibiting most commercial activities of U.S. and EU persons in Crimea and Sevastopol;

 

 

enhanced export controls and trade sanctions targeting Russia’s imports of technological goods as a whole, including tighter controls on exports and reexports of dual-use items, stricter licensing policy with respect to issuing export licenses, and/or increased use of “end-use” controls to block or impose licensing requirements on exports, as well as higher import tariffs and a prohibition on exporting luxury goods to Russia and Belarus;

 

 

closure of airspace to Russian aircraft; and

 

 

ban on imports of Russian oil, liquefied natural gas and coal to the United States.

As the conflict in Ukraine continues, there can be no certainty regarding whether the governmental authorities in the United States, the European Union, the United Kingdom or other countries will impose additional sanctions, export controls or other measures targeting Russia, Belarus or other territories.

Our business must be conducted in compliance with applicable economic and trade sanctions laws and regulations, including those administered and enforced by the U.S. Department of Treasury’s Office of Foreign Assets Control, the U.S. Department of State, the U.S. Department of Commerce, the United Nations Security Council and other relevant governmental authorities. We must be ready to comply with the existing and any other potential additional measures imposed in connection with the conflict in Ukraine.

We do not currently have contracts directly with the entities or businesses on the sanctions list and we currently do not have operations, nor do we directly source materials from, Russia, Belarus, the Crimea Region of Ukraine, the so-called Donetsk People’s Republic or the so-called Luhansk People’s Republic. We continuously review and monitor our contractual relationships with suppliers and customers to establish whether any are the target of the applicable sanctions. In the unlikely event that we identify a party with which we have a business relationship that is the target of applicable sanctions, we would immediately activate a legal analysis of what gives rise to the business relationship, including any contract, to estimate the most appropriate course of action to comply with the sanction regulations, together with the impact of a contractual termination according to the applicable law, and then proceed as required by the regulatory authorities. However, given the range of possible outcomes, the full costs, burdens, and limitations on our and our customer’s and business partners’ businesses are currently unknown and may become significant.

Furthermore, even if an entity is not formally subject to sanctions, customers and business partners of such entity may decide to reevaluate or cancel projects with such entity for reputational or other reasons. As result of the ongoing conflict in Ukraine, many U.S. and other multi-national businesses across a variety of industries, including consumer goods and retail, food, energy, finance, media and entertainment, tech, travel and logistics, manufacturing and others, have indefinitely suspended their operations and paused all commercial activities in Russia and Belarus. Depending on the extent and breadth of sanctions, export controls and other measures that may be imposed in connection with the conflict in Ukraine, it is possible that our business, financial condition and results of operations could be materially and adversely affected.

We face significant competition that may cause us to lose market share.

The oilfield services industry is highly competitive and has relatively few barriers to entry. The principal competitive factors impacting sales of our services are price, reputation and technical expertise, equipment and service quality and health and safety standards. The market is also fragmented and includes numerous small companies capable of competing effectively in our markets on a local basis, as well as several large companies

 

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that possess substantially greater financial and other resources than we do. Our larger competitors’ greater resources could allow those competitors to compete more effectively than we can. For instance, our larger competitors may offer services at below-market prices or bundle ancillary services at no additional cost our customers. We compete with large national and multi-national companies that have longer operating histories, greater financial, technical and other resources and greater name recognition than we do. Several of our competitors provide a broader array of services and have a stronger presence in more geographic markets.

Some jobs are awarded on a bid basis, which further increases competition based on price. Pricing is often the primary factor in determining which qualified contractor is awarded a job. The competitive environment may be further intensified by mergers and acquisitions among oil and natural gas companies or other events that have the effect of reducing the number of available customers. As a result of a combination of continued pressure from increased competition which began during the second half of 2018 and 2019 and decreased demand for our services in 2020 due to the COVID-19 pandemic, we had to lower the prices for our services, which adversely affected our results of operations. If competition remains the same or increases as a result of a continued industry downturn or future industry downturns, we may be required to lower our prices, which would adversely affect our results of operations. In the future, we may lose market share or be unable to maintain or increase prices for our present services or to acquire additional business opportunities, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our competitors may be able to respond more quickly to new or emerging technologies and services and changes in customer requirements. The amount of equipment available may exceed demand, which could result in active price competition. In addition, depressed commodity prices lower demand for hydraulic fracturing equipment, which results in excess equipment and lower utilization rates. In addition, some E&P companies have commenced completing their wells using their own hydraulic fracturing equipment and personnel. Any increase in the development and utilization of in-house fracturing capabilities by our customers could decrease the demand for our services and have a material adverse impact on our business.

In addition, competition among oilfield service and equipment providers is affected by each provider’s reputation for safety and quality. We cannot assure that we will be able to maintain our competitive position.

Our business depends upon our ability to obtain specialized equipment, parts and key raw materials from third-party suppliers, and we may be vulnerable to delayed deliveries and future price increases.

While we operate a vertically integrated business, we purchase certain specialized equipment, parts and raw materials from third party suppliers and affiliates. At times during the commodity price cycle, there is a high demand for hydraulic fracturing and other oilfield services and extended lead times to obtain equipment and raw materials needed to provide these services. Should our current suppliers be unable or unwilling to provide the necessary equipment, parts or raw materials or otherwise fail to deliver the products timely and in the quantities required, any resulting delays in the provision of our services could have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, future price increases for this type of equipment, parts and raw materials could negatively impact our ability to purchase new equipment, to update or expand our existing fleet, to timely repair equipment in our existing fleet or meet the current demands of our customers.

We currently rely on a limited number of suppliers for major equipment to build new electric-powered hydraulic fracturing fleets utilizing Clean Fleet® technology, and our reliance on these vendors exposes us to risks including price and timing of delivery.

We currently rely on a limited number of suppliers for major equipment to build our new electric-powered hydraulic fracturing fleets utilizing Clean Fleet® technology. During periods in which fracturing services are in high demand, we may experience delays in obtaining certain parts that are used in fabricating and assembling

 

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our fleets. If demand for hydraulic fracturing fleets or the components necessary to build such fleets increases or these vendors face financial distress or bankruptcy, these vendors may not be able to provide the components necessary to construct our electric-powered hydraulic fracturing fleets on schedule or at the current price. If this were to occur, we could be required to seek other suppliers for major equipment to build our electric-powered hydraulic fracturing fleets, which may adversely affect our revenues or increase our costs.

Reliance upon a few large customers may adversely affect our revenue and operating results.

The majority of our revenue is generated from our hydraulic fracturing services. Due to the large percentage of our revenue historically derived from our hydraulic fracturing services with recurring customers and the limited availability of our fracturing units, we have had some degree of customer concentration. Our top ten customers represented approximately 50.8% and 52.8% of our consolidated revenue for the years ended December 31, 2021 and 2020, respectively on a pro forma basis. It is likely that we will depend on a relatively small number of customers for a significant portion of our revenue in the future. If a major customer fails to pay us, cash flow from operations would be impacted and our operating results and financial condition could be harmed. Additionally, if we were to lose any material customer, we may not be able to redeploy our equipment at similar utilization or pricing levels and such loss could have an adverse effect on our business until the equipment is redeployed at similar utilization or pricing levels.

We are exposed to counterparty credit risk. Nonpayment and nonperformance by our customers, suppliers or vendors could adversely impact our operations, cash flows and financial condition.

Weak economic conditions and widespread financial distress, including the significantly reduced global and national economic activity caused by the COVID-19 pandemic, could reduce the liquidity of our customers, suppliers or vendors, making it more difficult for them to meet their obligations to us. We are therefore subject to heightened risks of loss resulting from nonpayment or nonperformance by our customers, suppliers and vendors. Severe financial problems encountered by our customers, suppliers and vendors could limit our ability to collect amounts owed to us, or to enforce the performance of obligations owed to us under contractual arrangements. In the event that any of our customers was to enter into bankruptcy, we could lose all or a portion of the amounts owed to us by such customer, and we may be forced to cancel all or a portion of our service contracts with such customer at significant expense to us.

In addition, nonperformance by suppliers or vendors who have committed to provide us with critical products or services could raise our costs or interfere with our ability to successfully conduct our business. All of the above may be exacerbated in the future as the COVID-19 outbreak and the governmental responses to the outbreak continue. These factors, combined with volatile prices of oil and natural gas, may precipitate a continued economic slowdown and/or a recession.

Oil and natural gas companies’ operations using hydraulic fracturing are substantially dependent on the availability of water. Restrictions on the ability to obtain water for E&P activities and the disposal of flowback and produced water may impact their operations and have a corresponding adverse effect on our business, results of operations and financial condition.

Water is an essential component of shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Our oil and natural gas producing customers’ access to water to be used in these processes may be adversely affected due to reasons such as periods of extended drought, privatization, third party competition for water in localized areas or the implementation of local or state governmental programs to monitor or restrict the beneficial use of water subject to their jurisdiction for hydraulic fracturing to assure adequate local water supplies. The occurrence of these or similar developments may result in limitations being placed on allocations of water due to needs by third party businesses with more senior contractual or permitting rights to the water. Our customers’ inability to locate or contractually acquire and sustain the

 

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receipt of sufficient amounts of water could adversely impact their E&P operations and have a corresponding adverse effect on our business, results of operations and financial condition.

Moreover, the imposition of new environmental regulations and other regulatory initiatives could include increased restrictions on our producing customers’ ability to dispose of flowback and produced water generated by hydraulic fracturing or other fluids resulting from E&P activities. Applicable laws impose restrictions and strict controls regarding the discharge of pollutants into waters of the United States and require that permits or other approvals be obtained to discharge pollutants to such waters. Additionally, regulations implemented under both federal and state laws prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the natural gas and oil industry into coastal waters. These laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and hazardous substances. Compliance with current and future environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells and any inability to secure transportation and access to disposal wells with sufficient capacity to accept all of our flowback and produced water on economic terms may increase our customers’ operating costs and could result in restrictions, delays, or cancellations of our customers’ operations, the extent of which cannot be predicted.

We rely on a few key employees whose absence or loss could adversely affect our business.

Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our executive team, including our Chief Executive Officer, Executive Chairman, Chief Operating Officer, Chief Legal Officer and Chief Financial Officer, could disrupt our operations. We do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.

If we are unable to employ a sufficient number of skilled and qualified workers, our capacity and profitability could be diminished and our growth potential could be impaired.

The delivery of our services requires skilled and qualified workers with specialized skills and experience who can perform physically demanding work. As a result of the volatility of the oilfield services industry and the demanding nature of the work, workers may choose to pursue employment in fields that offer a more desirable work environment at wage rates that are competitive. Our ability to be productive and profitable will depend upon our ability to employ and retain skilled workers. In addition, our ability to expand our operations depends in part on our ability to increase the size of our skilled labor force. The demand for skilled workers is high, and the supply is limited. As a result, competition for experienced oilfield service personnel is intense, and we face significant challenges in competing for crews and management with large and well-established competitors. 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. If either of these events were to occur, our capacity and profitability could be diminished and our growth potential could be impaired.

A negative shift in investor sentiment of the oil and gas industry has had and could in the future have adverse effects on our customers’ operations and ability to raise debt and equity capital.

Certain segments of the investor community have developed negative sentiment towards investing in our industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and gas and related services representation in certain key equity market indices. In addition, some investors, including investment advisors and certain sovereign wealth funds, pension funds, university endowments and family foundations, have stated policies to disinvest in the oil and gas sector based on their social and environmental considerations. Certain other stakeholders have also pressured commercial and investment banks and other

 

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lenders and investors to stop financing oil and gas production and related infrastructure projects, which adversely affects our customers. Such developments, including environmental activism and initiatives aimed at limiting climate change and reducing air pollution, could result in downward pressure on the stock prices of oilfield service companies, including ours. This may also potentially result in a reduction of available capital funding for potential transactions, impacting our future financial results.

Additionally, negative public perception regarding our industry may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines or enforcement interpretations. Additionally, environmental groups, landowners, local groups and other advocates may oppose our customers’ operations through organized protests, attempts to block or sabotage our customers’ operations, intervene in regulatory or administrative proceedings involving our customers’ assets, or file lawsuits or other actions designed to prevent, disrupt or delay the development or operation of our customers’ assets. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation for our customers, which could reduce our customers’ production levels over time and, as a result, may reduce demand for our services. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits that our customers require to conduct their operations to be withheld, delayed or burdened by requirements that restrict our customers’ ability to profitably conduct their businesses, which would also reduce demand for our services. Ultimately, this could make it more difficult to secure funding for our operations.

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with fossil fuel-related assets could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on the price of our common stock and our or our customers’ access to and cost of capital. Also, institutional lenders may decide not to provide funding for fossil fuel energy companies based on climate change-related concerns, which could affect our or our customers’ access to capital for potential growth projects.

Our operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could limit our ability to grow.

The oilfield services industry is capital intensive. In conducting our business and operations, we have made, and expect to continue to make, substantial capital expenditures. Our total capital expenditures were approximately $48.0 million for the year ended December 31, 2020 and $87.4 million for the year ended December 31, 2021. We have historically financed capital expenditures primarily with cash generated by operations, equipment and vendor financing, borrowings under our Old ABL Credit Facility (as defined herein) and other debt financing. Following the completion of this offering, we intend to finance our capital expenditures primarily with cash on hand, cash flow from operations and borrowings under our New ABL Credit Facility. However, we have limited access to liquidity under our New ABL Credit Facility and may be unable to generate sufficient cash from operations and other capital resources to maintain planned or future levels of capital expenditures which, among other things, may prevent us from acquiring new equipment or properly maintaining our existing equipment. Further, any disruptions or continuing volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. This could put us at a competitive disadvantage or interfere with our growth plans. Further, our actual capital expenditures for 2022 or future years could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount we have available, we could be required to

 

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seek additional sources of capital, which may include debt financing, joint venture partnerships, sales of assets, offerings of debt or equity securities or other means. We may not be able to obtain any such alternative source of capital. We may be required to curtail or eliminate contemplated activities. If we can obtain alternative sources of capital, the terms of such alternative may not be favorable to us. In particular, the terms of any debt financing may include covenants that significantly restrict our operations. Our inability to grow as planned may reduce our chances of maintaining and improving profitability.

The growth of our business through recently completed acquisitions and potential future acquisitions may expose us to various risks, including those relating to difficulties in identifying suitable, accretive acquisition opportunities and integrating businesses, assets and personnel, as well as difficulties in obtaining financing for targeted acquisitions and the potential for increased leverage or debt service requirements.

We have pursued and intend to continue to pursue selected, accretive acquisitions of complementary assets and businesses. Acquisitions involve numerous risks, including:

 

 

unanticipated costs and exposure to liabilities assumed in connection with the acquired business or assets, including but not limited to environmental liabilities and title issues;

 

 

difficulties in integrating the operations and assets of the acquired business and the acquired personnel;

 

 

complexities associated with managing a larger, more complex, integrated business;

 

 

limitations on our ability to properly assess and maintain an effective internal control environment over an acquired business;

 

 

potential losses of key employees, customers and business partners of the acquired business;

 

 

performance shortfalls at one or both of the companies as a result of the diversion of management’s attention from their day-to-day responsibilities caused by completing an acquisition and integrating an acquired business into the combined company;

 

 

risks of entering markets in which we have limited prior experience; and

 

 

increases in our expenses and working capital requirements;

The process of integrating an acquired business, including in connection with our recently completed FTSI Acquisition, may involve unforeseen costs and delays or other operational, technical and financial difficulties and may require a significant amount of time and resources. For example, we may experience difficulties in integrating FTSI’s operations into our business and in realizing expected benefits and synergies from the FTSI Acquisition. The integration process may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. If we are unable to successfully integrate the operations of FTSI with our business, we may be unable to achieve consolidation savings and may incur unanticipated costs and liabilities. Likewise, we do not have a formal estimate of mineral reserves for West Munger, and the productivity of that site could be less than we are anticipating. We could also encounter difficulties in the development of the mining and sand processing capacity at our West Munger Facility and may not realize the expected benefits from our investments in Flotek and FHE. Our failure to incorporate the acquired business and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our business, liquidity position, financial condition, prospects and results of operations. Furthermore, there is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions.

In addition, we may not have sufficient capital resources to complete any additional acquisitions. Historically, we have financed our acquisitions primarily with funding from our equity investors, commercial borrowings and

 

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cash generated by operations. We may incur substantial indebtedness to finance future acquisitions and also may issue equity, debt or convertible securities in connection with such acquisitions. Debt service requirements could represent a significant burden on our results of operations and financial condition, and the issuance of additional equity or convertible securities could be dilutive to our existing shareholders. Furthermore, we may not be able to obtain additional financing as needed or on satisfactory terms.

Our ability to continue to grow through acquisitions and manage growth will require us to continue to invest in operational, financial and management information systems and to attract, retain, motivate and effectively manage our employees. The inability to effectively manage the integration of acquisitions, including in connection with our Corporate Reorganization, could reduce our focus on current operations, which, in turn, could negatively impact our earnings and growth. Our financial position and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.

Concerns over general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.

Concerns over global economic conditions, geopolitical issues, including the recent conflict between Russia and Ukraine, supply chain disruptions, interest rates, inflation, the availability and cost of credit and the United States and foreign financial markets have contributed to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatility in commodity prices, business and consumer confidence and unemployment rates, have precipitated an economic slowdown. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish further, which could impact the price at which oil, natural gas and natural gas liquids can be sold, which could affect the ability of our customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition.

Inflation may adversely affect our operating results.

Inflationary factors such as increases in the labor costs, material costs and overhead costs may adversely affect our operating results. We do not believe that inflation has had a material impact on our financial position or results of operations to date; however, a high rate of inflation, including a continuation of inflation at the current rate, may have an adverse effect on our reputation, business, financial condition, cash flows and results of operations.

Our indebtedness and liquidity needs could restrict our operations and make us more vulnerable to adverse economic conditions.

Our existing and future indebtedness, whether incurred in connection with acquisitions, operations or otherwise, and limited access to liquidity may adversely affect our operations and limit our growth, and we may have difficulty making debt service payments on such indebtedness as payments become due. Our level of indebtedness may affect our operations in several ways, including the following:

 

 

increasing our vulnerability to general adverse economic and industry conditions;

 

 

the covenants that are contained in the agreements governing our indebtedness could limit our ability to borrow funds, dispose of assets, pay dividends and make certain investments;

 

 

our debt covenants could also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

 

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any failure to comply with the financial or other debt covenants, including covenants that impose requirements to maintain certain financial ratios, could result in an event of default, which could result in some or all of our indebtedness becoming immediately due and payable;

 

 

our level of debt could impair our ability to obtain additional financing, or obtain additional financing on favorable terms, in the future for working capital, capital expenditures, acquisitions or other general corporate purposes; and

 

 

our business may not generate sufficient cash flow from operations to enable us to meet our obligations under our indebtedness.

Restrictions in our debt agreements and any future financing agreements may limit our ability to finance future operations, meet capital needs or capitalize on potential acquisitions and other business opportunities.

The operating and financial restrictions and covenants in existing and future debt agreements could restrict our ability to finance future operations, meet capital needs or to expand or pursue our business activities. For example, our debt agreements will restrict or limit our ability to:

 

 

grant liens;

 

incur additional indebtedness;

 

engage in a merger, consolidation or dissolution;

 

enter into transactions with affiliates;

 

sell or otherwise dispose of assets, businesses and operations;

 

materially alter the character of our business as conducted at the closing of this offering; and

 

make acquisitions, investments and capital expenditures and pay dividends.

Furthermore, our debt agreements contain certain other operating and financial covenants. Our ability to comply with the covenants and restrictions contained in our debt agreements may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our debt agreements, a significant portion of our indebtedness may become immediately due and payable, and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. Any subsequent replacement of our debt agreements or any new indebtedness could have similar or greater restrictions. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facilities and Other Financing Arrangements.”

An increase in interest rates would increase the cost of servicing our indebtedness and could reduce our profitability, decrease our liquidity and impact our solvency.

A number of our existing debt agreements provide for, and our future debt agreements may provide for, debt incurred thereunder to bear interest at variable rates. As a result, increases in interest rates could increase the cost of servicing such indebtedness and materially reduce our profitability and cash flows.

Our operations are subject to unforeseen interruptions and hazards inherent in the oil and natural gas industry, for which we may not be adequately insured and which could cause us to lose customers and substantial revenue.

Our operations are exposed to the risks inherent to our industry, such as equipment defects, vehicle accidents, fires, explosions, blowouts, surface cratering, uncontrollable flows of gas or well fluids, pipe or pipeline failures, abnormally pressured formations and various environmental hazards, such as oil spills and releases of, and exposure to, hazardous substances. For example, our operations are subject to risks associated with hydraulic

 

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fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. In addition, our operations are exposed to potential natural disasters, including blizzards, tornadoes, storms, floods, other adverse weather conditions and earthquakes. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties or other damage resulting in curtailment or suspension of our operations. The cost of managing such risks may be significant. The frequency and severity of such incidents will affect operating costs, insurability and relationships with customers, employees and regulators. In particular, our customers may elect not to purchase our services if they view our environmental or safety record as unacceptable, which could cause us to lose customers and substantial revenues.

Our insurance may not be adequate to cover all losses or liabilities we may suffer. Furthermore, we may be unable to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased and could escalate further. In addition, sub-limits have been imposed for certain risks. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. If we were to incur a significant liability for which we are not fully insured, it could have a material adverse effect on our business, results of operations and financial condition. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position.

Since hydraulic fracturing activities are part of our operations, they are covered by our insurance against claims made for bodily injury, property damage and clean-up costs stemming from a sudden and accidental pollution event. However, we may not have coverage if we are unaware of the pollution event and unable to report the “occurrence” to our insurance company within the time frame required under our insurance policy. In addition, these policies do not provide coverage for all liabilities, and the insurance coverage may not be adequate to cover claims that may arise, or we may not be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.

Inaccuracies in our estimates of mineral reserves and resource deposits, or deficiencies in our title to those deposits, could result in our inability to mine the deposits or require us to pay higher than expected costs.

We base our mineral reserve and resource estimates on engineering, economic and geological data assembled and analyzed by our mining engineers, which are reviewed periodically by outside firms. However, commercial silica reserve estimates are necessarily imprecise and depend to some extent on statistical inferences drawn from available drilling data, which may prove unreliable. There are numerous uncertainties inherent in estimating quantities and qualities of commercial silica reserves and non-reserve commercial silica deposits and costs to mine recoverable reserves, many of which are beyond our control and any of which could cause actual results to differ materially from our expectations. These uncertainties include:

 

 

geological and mining conditions and/or effects from prior mining that may not be fully identified by available data or that may differ from experience;

 

 

assumptions regarding the effectiveness of our mining, quality control and training programs;

 

 

assumptions concerning future prices of commercial silica products, operating costs, mining technology improvements, development costs and reclamation costs; and

 

 

assumptions concerning future effects of regulation, including the issuance of required permits and taxes by governmental agencies.

 

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In addition, title to, and the area of, mineral properties and water rights may also be disputed. Mineral properties sometimes contain claims or transfer histories that examiners cannot verify. A successful claim that we do not have title to one or more of our properties or lack appropriate water rights could cause us to lose any rights to explore, develop and extract any minerals on that property, without compensation for our prior expenditures relating to such property. Any inaccuracy in our estimates related to our mineral reserves and non-reserve mineral deposits, or our title to such deposits, could result in our inability to mine the deposits or require us to pay higher than expected costs.

Additionally, a portion of our Alpine reserves are located on approximately 630 acres that we lease pursuant to a lease that terminates in 2052 and requires that we commence production from the leased premises by January 1, 2032. If we do not commence mining activities by January 1, 2032, our lease of this property would terminate and we would lose our interest in these reserves.

A terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States could adversely affect the U.S. and global economies and could prevent us from meeting financial and other obligations. We could experience loss of business, delays or defaults in payments from payors or disruptions of fuel supplies and markets if pipelines, production facilities, processing plants, refineries or transportation facilities are direct targets or indirect casualties of an act of terror or war. Such activities could reduce the overall demand for oil and natural gas, which, in turn, could also reduce the demand for our services. Terrorist activities and the threat of potential terrorist activities and any resulting economic downturn could adversely affect our results of operations, impair our ability to raise capital or otherwise adversely impact our ability to realize certain business strategies.

Increasing trucking regulations may increase our costs and negatively impact our results of operations.

In connection with our business operations, including the transportation and relocation of our hydraulic fracking equipment and shipment of frac sand, we operate trucks and other heavy equipment. As such, we operate as a motor carrier in providing certain of our services and therefore are subject to regulation by the United States Department of Transportation (“DOT”) and by various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations, driver licensing, insurance requirements, financial reporting and review of certain mergers, consolidations and acquisitions, and transportation of hazardous materials. Our trucking operations are subject to possible regulatory and legislative changes that may increase our costs. 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 or work in any specific period, onboard black box recorder device requirements or limits on vehicle weight and size.

Interstate motor carrier operations are subject to safety requirements prescribed by the DOT. To a large degree, intrastate motor carrier operations are subject to state safety regulations that mirror federal regulations. Matters such as the weight and dimensions of equipment are also subject to federal and state regulations. 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.

Certain motor vehicle operators require registration 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 that could result in a suspension of operations.

 

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We may be subject to claims for personal injury and property damage, which could materially adversely affect our financial condition and results of operations.

We operate with most of our customers under master service agreements (“MSAs”). We endeavor to allocate potential liabilities and risks between the parties in the MSAs. Generally, under our MSAs, including those relating to our hydraulic fracturing services, we assume responsibility for, including control and removal of, pollution or contamination which originates above surface and originates from our equipment or services. Our customer assumes responsibility for, including control and removal of, all other pollution or contamination which may occur during operations, including that which may result from seepage or any other uncontrolled flow of drilling fluids. We may have liability in such cases if we are negligent or commit willful acts. Generally, our customers also agree to indemnify us against claims arising from their employees’ personal injury or death to the extent that, in the case of our hydraulic fracturing operations, their employees are injured or their properties are damaged by such operations, unless resulting from our gross negligence or willful misconduct. Similarly, we generally agree to indemnify our customers for liabilities arising from personal injury to or death of any of our employees, unless resulting from gross negligence or willful misconduct of the customer. In addition, our customers generally agree to indemnify us for loss or destruction of customer-owned property or equipment and in turn, we agree to indemnify our customers for loss or destruction of property or equipment we own. Losses due to catastrophic events, such as blowouts, are generally the responsibility of the customer. However, despite this general allocation of risk, we might not succeed in enforcing such contractual allocation, might incur an unforeseen liability falling outside the scope of such allocation or may be required to enter into an MSA with terms that vary from the above allocations of risk. Litigation arising from a catastrophic occurrence at a location where our equipment and services are being used may result in our being named as a defendant in lawsuits asserting large claims. As a result, we may incur substantial losses which could materially and adversely affect our financial condition and results of operation.

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. For example, we depend on digital technologies to perform many of our services and process and record operational and accounting data. At the same time, cyber incidents, including deliberate attacks or unintentional events, 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, and those of our vendors, 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 and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems and insurance coverage for protecting against cyber security risks may not be sufficient. 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 any vulnerability to cyber incidents. Our insurance coverage for cyberattacks may not be sufficient to cover all the losses we may experience as a result of such cyberattacks.

If we are unable to fully protect our intellectual property rights, we may suffer a loss in our competitive advantage or market share.

While we have acquired licenses from USWS to construct electric-powered hydraulic fracturing fleets utilizing Clean Fleet® technology, we do not have patents or patent applications relating to many of our key processes and technology. If we are not able to maintain the confidentiality of our trade secrets, or if our competitors are able to replicate our technology or services, our competitive advantage would be diminished. We also cannot

 

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ensure that any patents we may obtain in the future would provide us with any significant commercial benefit or would allow us to prevent our competitors from employing comparable technologies or processes.

We may be adversely affected by disputes regarding intellectual property rights of third parties.

Third parties from time to time may initiate litigation against us by asserting that the conduct of our business infringes, misappropriates or otherwise violates intellectual property rights. We may not prevail in any such legal proceedings related to such claims, and our products and services may be found to infringe, impair, misappropriate, dilute or otherwise violate the intellectual property rights of others. If we are sued for infringement and lose, we could be required to pay substantial damages and/or be enjoined from using or selling the infringing products or technology. Any legal proceeding concerning intellectual property could be protracted and costly regardless of the merits of any claim and is inherently unpredictable and could have a material adverse effect on our financial condition, regardless of its outcome.

If we were to discover that our technologies or products infringe valid intellectual property rights of third parties, we may need to obtain licenses from these parties or substantially re-engineer our products in order to avoid infringement. We may not be able to obtain the necessary licenses on acceptable terms, or at all, or be able to re-engineer our products successfully. If our inability to obtain required licenses for our technologies or products prevents us from selling our products, that could adversely impact our financial condition and results of operations.

Additionally, we currently license certain third party intellectual property in connection with our business, and the loss of any such license could adversely impact our financial condition and results of operations.

Seasonal weather conditions, natural disasters, public health crises, and other catastrophic events outside of our control could severely disrupt normal operations and harm our business.

Our operations are located in different regions of the United States. Some of these areas are adversely affected by seasonal weather conditions, primarily in the winter and spring. However, as evidenced by the severe winter weather experienced in the southern United States and Canada during February 2021, weather-related hazards can exist in almost all the areas where we operate. During periods of heavy snow, ice or rain, we may be unable to move our equipment between locations or obtain adequate supplies of raw material or fuel, thereby reducing our ability to provide services and generate revenues. The exploration activities of our customers may also be affected during such periods of adverse weather conditions. Additionally, extended drought conditions in our operating regions could impact our ability or our customers’ ability to source sufficient water or increase the cost for such water. As a result, a natural disaster or inclement weather conditions could severely disrupt the normal operation of our business and adversely impact our financial condition and results of operations. Climate change may exacerbate the likelihood or intensity of such natural disasters or inclement weather conditions. Furthermore, if the area in which we operate or the market demand for oil and natural gas is affected by a public health crisis, such as the coronavirus, or other similar catastrophic event outside of our control, our business and results of operations could suffer.

Following the FTSI Acquisition, our fleet includes substantial legacy capacity that may require increased levels of maintenance and capital expenditures to be maintained in good operating condition, is less efficient than our Pre-Acquisition Fleets, and may be subject to a higher likelihood of mechanical failure, an inability to economically return to service or requirement to be scrapped. If we are unable to manage retiring some portion of our fleet efficiently, or if we are unable meet the changing needs of our customers, our results will deteriorate and our financial position and cash flows could be materially adversely affected.

While approximately 90% of our Pre-Acquisition Fleets are less than six years old, with 60% having Tier IV engines and 49% having dual fuel capabilities as of March 31, 2022, many of the fleets we acquired in the FTSI

 

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Acquisition are substantially older. This legacy portion of our fleet is generally less technologically advanced than our Pre-Acquisition Fleets, may require additional maintenance and capital expenditures to be kept in good operating condition and as a consequence may be subject to longer or more frequent periods of unavailability. Prolonged periods of unavailability of one or more of our older fleets could have a material adverse effect on our financial position, results of operations and cash flows. In addition, we expect that the fleets we acquired in the FTSI Acquisition may be less attractive and less fuel efficient than our competitors’ newer fleets, putting us at a competitive disadvantage. While we are retiring 650,000 HHP of FTSI’s older, emissions-intensive fleets, we may be unable to successfully replace those retired fleets with comparable production that meets our lower-emissions profile or our desired rate of return for our fleets.

Moreover, this legacy portion of our fleet may be unable to reduce our customers’ relative emissions footprint or satisfy the ESG objectives of our customers, unlike our Pre-Acquisition Fleet and including our electric powered hydraulic fracturing fleets. As our customers have become more focused on ESG, we have introduced products and services such as our electric powered hydraulic fracturing fleets to meet their needs. We may commit capital to research and development of equipment to meet our customers’ expectations that is never placed into service or we may place equipment into service, such as our electric powered hydraulic fracturing fleets, that do not meet their expectations. Further, if our customers’ and investors’ expectations for emissions reductions accelerate, we may be unable to develop or acquire technology, or ultimately equip our fleets with technology to meet such expectations, which may have a material adverse effect on our financial position, results of operations and cash flows.

Risks related to environmental and regulatory matters

Our operations and the operations of our customers are subject to environmental, health and safety laws and regulations, and future compliance, claims, and liabilities relating to such matters may have a material adverse effect on our results of operations, financial position or cash flows.

The nature of our operations, and those of our customers, including the handling, transporting and disposing of a variety of fluids and substances, including hydraulic fracturing fluids and other regulated substances, air emissions, and wastewater discharges exposes us and our customers to some risk of environmental liability, including the release of pollutants from oil and natural gas wells and associated equipment to the environment. We are also subject to laws and regulations associated with sand mining and equipment manufacturing operations, including the processing, and the related storage, handling, transportation and disposal of raw materials, products and wastes. The cost of compliance with these laws can be significant. Failure to properly handle, transport or dispose of these materials or otherwise conduct our operations in accordance with these and other environmental, health and safety laws could expose us to substantial liability for administrative, civil and criminal penalties, cleanup and site restoration costs and liability associated with releases of such materials, damages to natural resources and other damages, as well as potentially impair our ability to conduct our operations. Such liability is commonly on a strict, joint and several liability basis, without regard to fault. Liability may be imposed as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third parties. Neighboring landowners and other third parties may file claims against us for personal injury or property damage allegedly caused by the release of pollutants into the environment. Environmental, health and safety laws and regulations have changed in the past, and they may change in the future and become more stringent. Current and future claims and liabilities may have a material adverse effect on us because of potential adverse outcomes, defense costs, diversion of management resources, unavailability of insurance coverage and other factors. The ultimate costs of these liabilities are difficult to determine and may exceed any reserves we may have established. If existing environmental, health and safety requirements or enforcement policies change, we may be required to make significant unanticipated

 

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capital and operating expenditures. For more information, see “Business—Environmental and Occupational Health and Safety Regulations.”

Our operations, and those of our customers, are subject to a series of risks arising from climate change.

Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of carbon dioxide, methane and other GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources.

In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, President Biden has established addressing climate change as a priority of his administration and has issued several executive orders addressing climate change. Moreover, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the federal Clean Air Act (“CAA”), the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, and together with the DOT, set GHG emissions and fuel economy standards for vehicles in the United States. The regulation of methane from oil and gas facilities has been subject to uncertainty in recent years. The EPA previously had promulgated new source performance standards (“NSPS”) imposing limitations on methane emissions from sources in the oil and gas sector. Subsequently, in September 2020, the Trump Administration rescinded those methane standards and removed the transmission and storage segments from the oil and gas source category under the CAA’s NSPS. However, in June 2021, President Biden signed a resolution passed by the U.S. Congress under the Congressional Review Act nullifying the September 2020 rule, effectively reinstating the prior standards. In November 2021, as required by President Biden’s executive order, the EPA proposed new regulations to expand NSPS requirements for oil and gas sector sources and establish comprehensive standards of performance and emission guidelines for methane and volatile organic compound emissions from existing operations in the oil and gas sector, including the exploration and production, transmission, processing, and storage segments. The EPA has announced that the agency hopes to finalize these rulemakings by the end of 2022. Once finalized, the regulations are likely to be subject to legal challenge and will also need to be incorporated into the states’ implementation plans, which will need to be approved by the EPA in individual rulemakings that could also be subject to legal challenge. The reinstatement of direct regulation of methane emission for new sources and the promulgation of requirements for existing oil and gas customers could result in increased costs for our customers and consequently adversely affect demand for our services.

Separately, various states and groups of states have adopted or are considering adopting legislation, regulation or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. For example, several states, including Pennsylvania and New Mexico, have proposed or adopted regulations restricting the emission of methane from E&P activities. At the international level, the United Nations-sponsored “Paris Agreement” requires member states to submit non-binding, individually-determined reduction goals known as Nationally Determined Contributions every five years after 2020. President Biden has recommitted the United States to the Paris Agreement and, in April 2021, announced a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. In November 2021, President Biden released “The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050,” which, among other things, explains that the U.S. and EU are co-leading the “Global Methane Pledge” that aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels. The impacts of these orders, pledges, agreements, and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, cannot be predicted at this time.

 

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Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate change related pledges made by certain candidates now in public office. On January 27, 2021, President Biden issued an executive order that calls for substantial action on climate change, including, among other things, the increased use of zero-emission vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risks across government agencies and economic sectors. The Biden Administration has also issued orders temporarily suspending the issuance of authorizations, and suspending the issuance of new leases pending a study, for oil and gas development on federal lands. For more information, see our regulatory disclosure titled “Regulation of Hydraulic Fracturing and Related Activities.” As a result, we cannot predict the full impact of these developments or whether the Biden Administration may pursue further restrictions. Other actions that could be pursued by the Biden Administration may include the imposition of more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities, as well as more restrictive GHG emission limitations for oil and gas facilities. Litigation risks are also increasing as a number of entities have sought to bring suit against various oil and natural gas companies in state or federal court, alleging among other things, that such companies created public nuisances by producing fuels that contributed to climate change or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts.

There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies may elect in the future to shift some or all of their investments into non-fossil fuel related sectors. Institutional lenders who provide financing to fossil fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. Recently, President Biden signed an executive order calling for the development of a “climate finance plan” and, separately, the Federal Reserve announced that is has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Limitation of investments in and financing for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities. Additionally, the SEC recently proposed new rules relating to the disclosure of a range of climate-related risks. We are currently assessing this rule but at this time we cannot predict the costs of implementation or any potential adverse impacts resulting from the rule. To the extent this rule is finalized as proposed, we or our customers could incur increased costs related to the assessment and disclosure of climate-related risks. In addition, enhanced climate disclosure requirements could accelerate the trend of certain stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon intensive sectors.

The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate the GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for oil and natural gas, which could reduce demand for our services. Additionally, political, litigation and financial risks may result in our customers restricting or cancelling production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing their ability to continue to operate in an economic manner, which also could reduce the demand for our services. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.

 

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Finally, many scientists have concluded that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climate events that could have an adverse effect on our customers’ operations.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews and investment practices for such activities may serve to limit future oil and natural gas E&P activities and could have a material adverse effect on our results of operations and business.

Various federal, state and local legislative and regulatory initiatives have been, or could be undertaken which could result in additional requirements or restrictions being imposed on hydraulic fracturing operations. Currently, hydraulic fracturing is generally exempt from federal regulation under the Safe Drinking Water Act Underground Injection Control (the “SDWA UIC”) program and is typically regulated by state oil and gas commissions or similar agencies. However, certain federal agencies have increased scrutiny and regulation. For example, in late 2016, the EPA released a final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain limited circumstances. Additionally, the EPA has asserted regulatory authority pursuant to the SDWA UIC program over hydraulic fracturing activities involving the use of diesel fuel in the fracturing fluid and issued guidance of such activities. Furthermore, the U.S. Bureau of Land Management (the “BLM”) published a final rule in 2015 that established stringent standards relating to hydraulic fracturing on federal and Native American lands. The rule was rescinded, but the rescission is currently on appeal to the U.S. Court of Appeals for the Ninth Circuit. Similarly, the EPA has adopted rules on the capture of methane and other emissions released during hydraulic fracturing. In addition to federal regulatory actions, legislation has been introduced, but not enacted, in U.S. Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process.

Separately, the Biden Administration has taken action to restrict E&P activities, including hydraulic fracturing, on public lands. For more information, see “Business—Environmental and Occupational Health and Safety Regulations—Regulation of Hydraulic Fracturing and Related Activities.”

Many states and local governments have also adopted regulations that impose more stringent permitting, disclosure, disposal and well-construction requirements on hydraulic fracturing operations, including states where we or our customers operate, such as Texas, Colorado and North Dakota. States could also elect to place prohibitions on hydraulic fracturing, as several states have already done. In addition, some states have adopted broader sets of requirements related to oil and gas development more generally that could impact hydraulic fracturing activities. Separately, state and federal regulatory agencies have at times focused on a possible connection between hydraulic fracturing related activities, including the underground injection of wastewater into disposal wells, and the increased occurrence of seismic activity. Regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. To the extent any new regulations are adopted to restrict hydraulic fracturing activities or the disposal of fluids associated with such activities, it may adversely affect our customers and, as a result, demand for our services. For more information see “Business—Environmental and Occupational Health and Safety Regulations—Regulation of Hydraulic Fracturing and Related Activities.”

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to, and litigation concerning, oil and natural gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays for our customers or increased operating costs in the production of oil and natural gas, including from the developing shale plays, or could make it more difficult for us and our customers to perform hydraulic fracturing. The adoption of any additional

 

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laws or regulations regarding hydraulic fracturing or further restrictions on the availability of capital for hydraulic fracturing could potentially cause a decrease in the completion of new oil and natural gas wells and an associated decrease in demand for our services and increased compliance costs and time. Such a decrease could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition. Moreover, the increased competitiveness of alternative energy sources (such as wind, solar, geothermal, tidal and biofuels) or increased focus on reducing the use of combustion engines in transportation (such as governmental mandates that ban the sale of new gasoline-powered automobiles) could reduce demand for hydrocarbons and therefore for our services, which would lead to a reduction in our revenues.

Conservation measures, commercial development and technological advances could reduce demand for oil and natural gas and our services.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas, resulting in reduced demand for oilfield services. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

The commercial development of economically-viable alternative energy sources and related products (such as electric vehicles, wind, solar, geothermal, tidal, fuel cells and biofuels) could have a similar effect. In addition, certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and development, including the allowance of percentage depletion for oil and natural gas properties, may be eliminated as a result of proposed legislation. Any future decreases in the rate at which oil and natural gas reserves are discovered or developed, whether due to the passage of legislation, increased governmental regulation leading to limitations, or prohibitions on exploration and drilling activity, including hydraulic fracturing, or other factors, could have a material adverse effect on our business and financial condition, even in a stronger oil and natural gas price environment.

Additional restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct completion activities.

In the United States, the Endangered Species Act (the “ESA”) restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”). To the extent species that are listed under the ESA or similar state laws, or are protected under the MBTA, inhabit the areas where we or our customers operate, our operations and the operations of our customers could be adversely impacted. Moreover, drilling activities may be delayed, restricted or precluded in protected habitat areas or during certain seasons, such as breeding and nesting seasons. The listing of new species under the ESA in the areas where our customers operate similarly has the potential to adversely impact our operations and demand for our services as a result of restrictions on oil and gas activities. For example, recently there have been renewed calls to review protections currently in place for the dunes sagebrush lizard, whose habitat includes parts of the Permian Basin, and to reconsider listing the species under the ESA, and, separately, a lawsuit has been filed to list the eastern hellbender salamander, whose habitat includes parts of the Appalachian Basin. Additionally, on June 1, 2021, U.S. Fish & Wildlife Service (the “FWS”) proposed to list two distinct population segments of the lesser prairie-chicken under the ESA. Various stakeholders have, in consultation with the FWS, developed a voluntary conservation plan to protect dunes sagebrush lizard habitat and limit disturbance of the dunes sagebrush lizard by participants’ activities. The voluntary conservation plan is known as a Candidate Conservation Agreement with Assurances (“CCAA”). We have joined the CCAA in an effort to mitigate potential impacts on our business of a listing of the dunes sagebrush lizard by the FWS.

 

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In addition, as a result of one or more settlements approved by the FWS, the agency was required to make a determination on the listing of numerous other species as endangered or threatened under the ESA by the end of the FWS’ 2017 fiscal year. The FWS did not meet that deadline, but continues to evaluate whether to take action with respect to those species. Separately, on March 23, 2022, the FWS proposed a rule to redesignate the northern long-eared bat from a threatened species to an endangered species under the ESA. The designation of previously unidentified endangered or threatened species could cause our operations to become subject to operating restrictions or bans, and limit future development activity in affected areas. The FWS and similar state agencies may designate critical or suitable habitat areas that they believe are necessary for the survival of threatened or endangered species. In October 2021, the Biden administration published two rules that reversed changes made by the Trump administration, namely to the definition of “habitat” and a policy that made it easier to exclude territory from critical habitat. It is possible these rules could increase the portion of our customers’ operating areas that could be designated as critical habitat. Such a designation could materially restrict use of or access to federal, state and private lands.

Risks related to this offering and our Class A Common stock

ProFrac Holding Corp. is a holding company. ProFrac Holding Corp.’s only material asset after completion of this offering will be its equity interest in ProFrac LLC, and ProFrac Holding Corp. will accordingly be dependent upon distributions from ProFrac LLC to pay taxes, make payments under the Tax Receivable Agreement and cover its corporate and other overhead expenses.

ProFrac Holding Corp. is a holding company and will have no material assets after completion of this offering other than its equity interest in ProFrac LLC. ProFrac Holding Corp. will have no independent means of generating revenue. To the extent ProFrac LLC has available cash, we intend to cause ProFrac LLC to make (i) generally pro rata distributions to the holders of ProFrac LLC Units, including ProFrac Holding Corp., in an amount at least sufficient to allow ProFrac Holding Corp. to pay its taxes (and those of its wholly owned subsidiaries) and to make payments under the Tax Receivable Agreement it will enter into with the TRA Holders and any subsequent tax receivable agreement that it may enter into in connection with future acquisitions and (ii) non-pro rata payments to ProFrac Holding Corp. to reimburse it for its corporate and other overhead expenses. To the extent that ProFrac Holding Corp. needs funds and ProFrac LLC or its subsidiaries are restricted from making such distributions or payments under applicable law or regulation or under the terms of any current or future financing arrangements, or are otherwise unable to provide such funds, our liquidity and financial condition could be materially adversely affected.

Moreover, because ProFrac Holding Corp. will have no independent means of generating revenue, ProFrac Holding Corp.’s ability to make tax payments and payments under the Tax Receivable Agreement will be dependent on the ability of ProFrac LLC to make distributions to ProFrac Holding Corp. in an amount sufficient to cover ProFrac Holding Corp.’s tax obligations (and those of its wholly owned subsidiaries) and obligations under the Tax Receivable Agreement. This ability, in turn, may depend on the ability of ProFrac LLC’s subsidiaries to make distributions to it. We intend that such distributions from ProFrac LLC and its subsidiaries be funded with cash from operations or from future borrowings. The ability of ProFrac LLC, its subsidiaries and other entities in which it directly or indirectly holds an equity interest to make such distributions will be subject to, among other things, (i) the applicable provisions of Texas law (or other applicable jurisdiction) that may limit the amount of funds available for distribution and (ii) restrictions in relevant debt instruments issued by ProFrac LLC or its subsidiaries and other entities in which it directly or indirectly holds an equity interest. To the extent that ProFrac Holding Corp. is unable to make payments under the Tax Receivable Agreement for any reason, such payments will be deferred and will accrue interest until paid.

 

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Conflicts of interest could arise in the future between us, on the one hand, and Dan Wilks and Farris Wilks and entities owned by or affiliated with them, on the other hand, concerning among other things, business transactions, potential competitive business activities or business opportunities.

Conflicts of interest could arise in the future between us, on the one hand, and Dan Wilks and Farris Wilks and entities owned by or affiliated with them, on the other hand, concerning among other things, business transactions, potential competitive business activities or business opportunities. Dan Wilks and Farris Wilks and other businesses owned by or affiliated with them operate in the energy and oilfield services industries. In the normal course of business, we have engaged in transactions with some of these companies. For more information, please see “Certain Relationships and Related Party Transactions.” Furthermore, Dan Wilks and Farris Wilks and other businesses owned by or affiliated with them may now, or in the future, directly or indirectly, compete with us for investment or business opportunities.

Dan Wilks and Farris Wilks and their affiliates are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us and will not have any duty to refrain from engaging, directly or indirectly, in the same or similar business activities or lines of business as us, including those business activities or lines of business deemed to be competing with us, or doing business with any of our clients, customers or vendors.

Dan Wilks and Farris Wilks or their affiliates may become aware, from time to time, of certain business opportunities (such as acquisition opportunities) and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. In addition, Dan Wilks and Farris Wilks and their affiliates may dispose of their interests in energy or other oilfield services companies or other assets in the future, without any obligation to offer us the opportunity to purchase any of those interests or assets.

In any of these matters, the interests of Dan Wilks and Farris Wilks and their affiliates and other business owned by or affiliated with them may differ or conflict with the interests of our other shareholders. Any actual or perceived conflicts of interest with respect to the foregoing could have an adverse impact on the trading price of our Class A common stock.

The requirements of being a public company, including compliance with the reporting requirements of the Exchange Act and the requirements of Sarbanes-Oxley, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

As a public company, we will need to comply with new laws, regulations and requirements, certain corporate governance provisions of Sarbanes-Oxley, related regulations of the SEC and the requirements of Nasdaq, with which we are not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of time of our board of directors and management and will significantly increase our costs and expenses. We will need to:

 

 

institute a more comprehensive compliance function;

 

 

comply with rules promulgated by Nasdaq;

 

 

continue to prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;

 

 

establish new internal policies, such as those relating to insider trading; and

 

 

involve and retain to a greater degree outside counsel and accountants in the above activities.

 

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In addition, we expect that being a public company subject to these rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers. We are currently evaluating these rules, and we cannot predict or estimate the amount of additional costs we may incur or the timing of such costs.

We will be required to comply with certain provisions of Section 404 of Sarbanes-Oxley as early as our fiscal year ending December 31, 2022. Section 404 requires that we document and test our internal control over financial reporting and issue management’s assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm opine on those internal controls upon becoming a large accelerated filer, as defined in the SEC rules, or otherwise ceasing to qualify as an emerging growth company under the JOBS Act. We are evaluating our existing controls against the standards adopted by the Committee of Sponsoring Organizations of the Treadway Commission. During the course of our ongoing evaluation and integration of the internal control over financial reporting, we may identify areas requiring improvement, and we may have to design enhanced processes and controls to address issues identified through this review. For example, we anticipate the need to hire additional administrative and accounting personnel to conduct our financial reporting.

We cannot be certain at this time that we will be able to successfully complete the procedures, certification and attestation requirements of Section 404 or that we or our independent registered public accounting firm will not identify material weaknesses in our internal control over financial reporting. If we fail to comply with the requirements of Section 404 or if we or our independent registered public accounting firm identify and report such material weaknesses, the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the price of our Class A common stock. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, results of operations and financial condition.

The initial public offering price of our Class A common stock may not be indicative of the market price of our Class A common stock after this offering. In addition, an active, liquid and orderly trading market for our Class A common stock may not develop or be maintained, and our stock price may be volatile.

Prior to this offering, our Class A common stock was not traded on any market. An active, liquid and orderly trading market for our Class A common stock may not develop or be maintained after this offering. Active, liquid and orderly trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. The market price of our Class A common stock could vary significantly as a result of a number of factors, some of which are beyond our control. In the event of a drop in the market price of our Class A common stock, you could lose a substantial part or all of your investment in our Class A common stock. The initial public offering price will be negotiated between us and representatives of the underwriters, based on numerous factors which we discuss in “Underwriting,” and may not be indicative of the market price of our Class A common stock after this offering. Consequently, you may not be able to sell shares of our Class A common stock at prices equal to or greater than the price paid by you in this offering.

The following is a non-exhaustive list of factors that could affect our stock price:

 

 

our operating and financial performance

 

 

quarterly variations in our financial and operating results;

 

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the public reaction to our press releases, our other public announcements and our filings with the SEC;

 

 

strategic actions by our competitors;

 

 

our failure to meet revenue or earnings estimates by research analysts or other investors;

 

 

changes in revenue or earnings estimates, or changes in recommendations or withdrawal of research coverage, by equity research analysts;

 

 

speculation in the press or investment community;

 

 

the failure of research analysts to cover our common stock;

 

 

sales of our common stock by us or other shareholders, or the perception that such sales may occur;

 

 

changes in accounting principles, policies, guidance, interpretations or standards;

 

 

additions or departures of key management personnel;

 

 

actions by our stockholders;

 

 

general market conditions, including fluctuations in commodity prices;

 

 

domestic and international economic, legal and regulatory factors unrelated to our performance; and

 

 

the realization of any risks described under this “Risk Factors” section.

The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our Class A common stock. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company’s securities. Such litigation, if instituted against us, could result in very substantial costs, divert our management’s attention and resources and materially harm our business, operating results and financial condition.

The unaudited pro forma financial data included in this prospectus may not be representative of our actual financial condition and results of operations in the future.

The unaudited pro forma financial data included in this prospectus is presented for illustrative purposes only and is not necessarily indicative of what our actual financial position or results of operations would have been as of the dates indicated, nor is it indicative of our future operating results or financial position. The preparation of the pro forma financial information is based upon available information and certain assumptions and estimates that the Company currently believe are reasonable. There may be differences between preliminary estimates in the pro forma financial information and the final accounting presentation, which could result in material differences from the pro forma information presented in this prospectus in respect of our estimated financial position and results of operations. Accordingly, the Company’s business, assets, cash flows, results of operations and financial condition may differ significantly from those indicated by the unaudited pro forma financial data included in this prospectus. In addition, the assumptions used in preparing the unaudited pro forma financial data may not prove to be accurate and other factors may affect our financial condition or results of operations. Any potential decline in our financial condition or results of operations may cause significant variations in our stock price.

The Wilks have the ability to direct the voting of a majority of our voting stock, and their interests may conflict with those of our other stockholders.

Upon completion of this offering, the Wilks will own approximately 84.8% of our voting stock (or approximately 83.4% if the underwriters’ option to purchase additional shares is exercised in full). Assuming THRC Holdings

 

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and the Farris and Jo Ann Wilks 2022 Family Trust purchase an aggregate of up to $117.0 million, or 5,200,000 shares (based on the midpoint of the price range set forth on the cover page of this prospectus), of our Class A common stock in this offering, approximately the Wilks will own approximately 88.5% of our voting stock (or approximately 87.0% if the underwriters’ option to purchase additional shares is exercised in full). As a result, the Wilks will be able to control matters requiring stockholder approval, including the election of directors, changes to our organizational documents and significant corporate transactions. This concentration of ownership makes it unlikely that any other holder or group of holders of our Class A common stock will be able to affect the way we are managed or the direction of our business. The interests of the Wilks with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, may conflict with the interests of our other stockholders.

For example, the Wilks may have different tax and other positions from us, especially in light of the Tax Receivable Agreement, that could influence their decisions regarding whether and when to support the disposition of assets, the incurrence or refinancing of new or existing indebtedness, or the termination of the Tax Receivable Agreement and acceleration of our obligations thereunder. In addition, the determination of future tax reporting positions, the structuring of future transactions and the handling of any challenge by any taxing authority to our tax reporting positions may take into consideration tax or other considerations of the Wilks which may differ from the considerations of us or our other stockholders. Please read “Certain Relationships and Related Party Transactions—Tax Receivable Agreement.”

Furthermore, in connection with this offering, we expect to enter into a stockholders’ agreement with the Wilks that will address the right to designate nominees for election to our board following this offering. See “Certain Relationships and Related Party Transactions—Stockholders’ Agreement.” The existence of significant stockholders may have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may deem to be in the best interests of the Company. Moreover, the Wilks’ concentration of stock ownership may adversely affect the trading price of our Class A common stock to the extent investors perceive a disadvantage in owning stock of a company with significant stockholders.

A significant reduction by Dan Wilks and Farris Wilks of their ownership interests in us could adversely affect us.

We believe that the Wilks’ substantial ownership interest in us provides them with an economic incentive to assist us to be successful. Upon the expiration or earlier waiver of the lock-up restrictions on transfers or sales of our securities following the completion of this offering, the Wilks will not be subject to any obligation to maintain their ownership interest in us and may elect at any time thereafter to sell all or a substantial portion of or otherwise reduce their ownership interest in us. If the Wilks sell all or a substantial portion of their ownership interests in us, they may have less incentive to assist in our success and they may choose to resign from their positions as members of our board of directors. Such actions could adversely affect our ability to successfully implement our business strategies which could adversely affect our cash flows or results of operations.

Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, will contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our Class A common stock and could deprive our investors of the opportunity to receive a premium for their shares.

Our amended and restated certificate of incorporation will authorize our board of directors to issue preferred stock without stockholder approval in one or more series, designate the number of shares constituting any series, and fix the rights, preferences, privileges and restrictions thereof, including dividend rights, voting

 

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rights, rights and terms of redemption, redemption price or prices and liquidation preferences of such series. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders. These provisions include the following:

 

 

until we cease to be a controlled company, the members of our board of directors designated by the parties to the Stockholders’ Agreement will have a majority of the voting power of our board of directors;

 

 

after we cease to be a controlled company, dividing our board of directors into three classes of directors, with each class serving staggered three-year terms;

 

 

after we cease to be a controlled company, and subject to the terms of our Stockholders’ Agreement, providing that all vacancies, including newly created directorships, may, except as otherwise required by law or, if applicable, the rights of holders of a series of preferred stock, only be filled by the affirmative vote of a majority of directors then in office, even if less than a quorum (prior to such time, vacancies may also be filled by stockholders holding a majority of the outstanding shares);

 

 

after we cease to be a controlled company, permitting any action by stockholders to be taken only at an annual meeting or special meeting rather than by a written consent of the stockholders, subject to the rights of any series of preferred stock with respect to such rights;

 

 

after we cease to be a controlled company, permitting special meetings of our stockholders to be called only by our Chief Executive Officer, the Executive Chairman of our board of directors and our board of directors pursuant to a resolution adopted by the affirmative vote of a majority of the total number of authorized directors whether or not there exist any vacancies in previously authorized directorships;

 

 

after we cease to be a controlled company, and subject to the rights of the holders of shares of any series of our preferred stock and the terms of our Stockholders’ Agreement, requiring the affirmative vote of the holders of at least 66 2/3% in voting power of all then outstanding common stock entitled to vote generally in the election of directors, voting together as a single class, to remove any or all of the directors from office at any time, and directors will be removable only for “cause”;

 

 

prohibiting cumulative voting in the election of directors;

 

 

establishing advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders; and

 

 

providing that the board of directors is expressly authorized to adopt, or to alter or repeal our bylaws.

In addition, certain change of control events will have the effect of accelerating the payments due under the Tax Receivable Agreement, which could be substantial and accordingly serve as a disincentive to a potential acquirer of the Company. Please see “—In certain cases, payments under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits, if any, ProFrac Holding Corp. realizes in respect of the tax attributes subject to the Tax Receivable Agreement.”

Our amended and restated certificate of incorporation will 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, employees or agents.

Our amended and restated certificate of incorporation will provide that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware, or, if such court does not have subject matter jurisdiction thereof, the federal district court of the State of Delaware, will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action, suit or proceeding brought on our behalf, (ii) any action, suit or proceeding asserting a claim of breach of a fiduciary duty owed by

 

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any of our current or former directors, officers, employees or stockholders to us or our stockholders, (iii) any action, suit or proceeding asserting a claim arising pursuant to any provision of the Delaware General Corporation Law (the “DGCL”), our certificate of incorporation or our bylaws (as either may be amended or restated) or as to which the DGCL confers jurisdiction on the Court of Chancery of the State of Delaware, or (iv) any action, suit or proceeding asserting a claim governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our amended and restated certificate of incorporation described in the preceding sentences. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or stockholders, which may discourage such lawsuits against us and such persons. However, stockholders will not be deemed to have waived our compliance with the federal securities laws and the rules and regulations thereunder and the exclusive forum provision would not apply to suits brought to enforce a duty or liability created by the Securities Act or the Exchange Act.

Our amended and restated certificate of incorporation also provides that the federal district courts of the United States will be the exclusive forum for any complaint asserting a cause of action under the Securities Act. Section 22 of the Securities Act creates concurrent jurisdiction for federal and state courts over all suits brought to enforce any duty or liability created by the Securities Act or the rules and regulations thereunder. Accordingly, there is uncertainty as to whether a court would enforce this forum provision providing for exclusive jurisdiction of federal district courts with respect to suits brought to enforce any duty or liability created by the Securities Act. If a court were to find these provisions of our certificate of incorporation 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 or results of operations.

Investors in this offering will experience immediate and substantial dilution of $(19.44) per share.

Based on an assumed initial public offering price of $22.50 per share (the midpoint of the price range set forth on the cover of this prospectus), purchasers of our Class A common stock in this offering will experience an immediate and substantial dilution of $(19.44) per share in the net tangible book value per share of Class A common stock from the initial public offering price, and our historical and pro forma net tangible book value as of December 31, 2021 would be $1.20 per share and $3.06 per share, respectively. See “Dilution.”

We have discretion in the use of the net proceeds from this offering and may not use them effectively.

Our management will have discretion in the application of the net proceeds from this offering and could spend the proceeds in ways that do not improve our results of operations or enhance the value of our Class A common stock. We intend to use $172.2 million of such net proceeds to make an offer to repay outstanding borrowings under the New Term Loan Credit Facility (which each lender thereunder may accept or reject in its sole discretion) and use the remaining net proceeds to repay amounts outstanding under the Backstop Note in the amount of $22.0 million and to purchase the THRC FTSI Related Equity from THRC Holdings in the amount of $72.9 million. Any net proceeds in excess of these amounts will be used as described in “Use of Proceeds.” However, our use of these proceeds may differ substantially from our current plans. The failure by our management to apply these funds effectively could result in financial losses that could have a material adverse effect on our business and cause the price of our Class A common stock to decline.

 

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We do not intend to pay cash dividends on our Class A common stock and our existing debt agreements place certain restrictions on our ability to do so. Consequently, your only opportunity to achieve a return on your investment is if the price of our Class A common stock appreciates.

We do not anticipate paying any cash dividends on our Class A common stock in the foreseeable future. In addition, our existing debt agreements place, and we expect our future debt agreements will place, certain restrictions on our ability to pay cash dividends. Consequently, unless we revise our dividend policy, your only opportunity to achieve a return on your investment in us will be if you sell your Class A common stock at a price greater than you paid for it. There is no guarantee that the price of our Class A common stock that will prevail in the market will ever exceed the price that you pay in this offering.

Future sales of our Class A common stock in the public market, or the perception that such sales may occur, could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

We may issue or sell additional shares of Class A common stock or securities that are convertible or exchangeable therefor. After the completion of this offering, we will have 34,991,326 outstanding shares of Class A common stock (or 37,391,326 shares of Class A common stock if the underwriters’ option to purchase additional shares is exercised in full). This number includes 16,000,000 shares that we are selling in this offering and 2,400,000 shares that we may sell in this offering if the underwriters’ option to purchase additional shares is fully exercised, which may be resold immediately in the public market. Following the completion of this offering, and assuming full exercise of the underwriters’ option to purchase additional shares, the Wilks will own 17,359,338 shares of our Class A common stock and 101,586,572 shares of our Class B common stock, or approximately 84.8% of our total outstanding shares. Certain ProFrac LLC Unit Holders will be party to a registration rights agreement, which will require us to effect the registration of any shares of Class A common stock that they receive in exchange for their ProFrac LLC Units in certain circumstances no earlier than the expiration of the lock-up period contained in the underwriting agreement entered into in connection with this offering. In addition, we have agreed to file a resale shelf registration statement that registers the resale of shares issued to the West Munger Sellers (as defined herein).

In connection with this offering, we intend to file a registration statement with the SEC on Form S-8 providing for the registration of 11,040,000 shares of our Class A common stock issued or reserved for issuance under our long term incentive plan. Subject to the satisfaction of vesting conditions, the expiration of lock-up agreements and the requirements of Rule 144, shares registered under the registration statement on Form S-8 may be made available for resale immediately in the public market without restriction.

We cannot predict the size of future issuances of our Class A common stock or securities convertible into Class A common stock or the effect, if any, that future issuances and sales of shares of our Class A common stock will have on the market price of our Class A common stock. Sales of substantial amounts of our Class A common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A common stock.

The underwriters of this offering may waive or release parties to the lock-up agreements entered into in connection with this offering, which could adversely affect the price of our Class A common stock.

We, all of our directors that will own equity in us following the completion of this offering and all of our executive officers have entered or will enter into lock-up agreements pursuant to which we and they will be subject to certain restrictions with respect to the sale or other disposition of our Class A common stock for a period of 180 days following the date of this prospectus. The underwriters, at any time and without notice, may release all or any portion of the Class A common stock subject to the foregoing lock-up agreements. See “Underwriting” for more information on these agreements. If the restrictions under the lock-up agreements

 

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are waived, then the Class A common stock, subject to compliance with the Securities Act or exceptions therefrom, will be available for sale into the public markets, which could cause the market price of our Class A common stock to decline and impair our ability to raise capital.

ProFrac Holding Corp. will be required to make payments under the Tax Receivable Agreement for certain tax benefits that it may claim, and the amounts of such payments could be significant.

In connection with the closing of this offering, ProFrac Holding Corp. will enter into the Tax Receivable Agreement with the TRA Holders. This agreement will generally provide for the payment by ProFrac Holding Corp. to the TRA Holders of 85% of the net cash savings, if any, in U.S. federal, state and local income tax and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that ProFrac Holding Corp. actually realizes (or is deemed to realize in certain circumstances) in periods after this offering as a result of certain increases in tax basis available to ProFrac Holding Corp. as a result of acquisitions of ProFrac LLC Units in connection with this offering or pursuant to the exercise of the Redemption Right or the Call Right and certain benefits attributable to imputed interest. We will retain the benefit of the remaining 15% of any actual net cash tax savings.

The term of the Tax Receivable Agreement will commence upon the completion of this offering and will continue until all tax benefits that are subject to the Tax Receivable Agreement have been utilized or expired, unless we experience a change of control (as defined in the Tax Receivable Agreement, which includes certain mergers, asset sales, or other forms of business combinations) or the Tax Receivable Agreement otherwise terminates early (at our election or as a result of our breach or the commencement of bankruptcy or similar proceedings by or against us) and ProFrac Holding Corp. makes the termination payments specified in the Tax Receivable Agreement in connection with such change of control or other early termination. In the event that the Tax Receivable Agreement is not terminated, the payments under the Tax Receivable Agreement are anticipated to commence in 2023 and to continue for 15 years after the date of the last redemption of the ProFrac LLC Units.

The payment obligations under the Tax Receivable Agreement are ProFrac Holding Corp.’s obligations and not obligations of ProFrac LLC, and we expect that the payments required to be made under the Tax Receivable Agreement will be substantial. Estimating the amount and timing of payments that may become due under the Tax Receivable Agreement is by its nature imprecise. For purposes of the Tax Receivable Agreement, net cash tax savings generally are calculated by comparing ProFrac Holding Corp.’s actual tax liability (determined by using the actual applicable U.S. federal income tax rate and an assumed combined state and local income and franchise tax rate) to the amount ProFrac Holding Corp. would have been required to pay had it not been able to utilize any of the tax benefits subject to the Tax Receivable Agreement. The actual increases in tax basis covered by the Tax Receivable Agreement, as well as the amount and timing of any payments under the Tax Receivable Agreement, will vary depending on a number of factors, including the timing of any redemption of ProFrac LLC Units, the price of ProFrac Holding Corp.’s Class A common stock at the time of each redemption, the extent to which such redemptions are taxable transactions, the amount of the redeeming ProFrac LLC Unit Holder’s tax basis in its ProFrac LLC Units at the time of the relevant redemption, the depreciation and amortization periods that apply to the increase in tax basis, the amount and timing of taxable income we generate in the future, the U.S. federal income tax rates then applicable, and the portion of ProFrac Holding Corp.’s payments under the Tax Receivable Agreement that constitute imputed interest or give rise to depreciable or amortizable tax basis. Any distributions made by ProFrac LLC to ProFrac Holding Corp. in order to enable ProFrac Holding Corp. to make payments under the Tax Receivable Agreement, as well as any corresponding pro rata distributions made to the ProFrac LLC Unit Holders, could have an adverse impact on our liquidity.

 

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The payments under the Tax Receivable Agreement will not be conditioned upon a TRA Holder having a continued ownership interest in ProFrac Holding Corp. or ProFrac LLC. For additional information regarding the Tax Receivable Agreement, see “Certain Relationships and Related Party Transactions—Tax Receivable Agreement.”

In certain cases, payments under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits, if any, ProFrac Holding Corp. realizes in respect of the tax attributes subject to the Tax Receivable Agreement.

If we experience a change of control (as defined under the Tax Receivable Agreement, which includes certain mergers, asset sales and other forms of business combinations) or the Tax Receivable Agreement otherwise terminates early (at our election or as a result of our breach or the commencement of bankruptcy or similar proceedings by or against us), ProFrac Holding Corp.’s obligations under the Tax Receivable Agreement would accelerate and ProFrac Holding Corp. would be required to make an immediate payment equal to the present value of the anticipated future payments to be made by it under the Tax Receivable Agreement (determined by applying a discount rate equal to (i) the greater of (A) 0.25% and (B) the 180-Day Average Secured Overnight Financing Rate (“SOFR”), plus (ii) 150 basis points) and such payment is expected to be substantial. The calculation of anticipated future payments will be based upon certain assumptions and deemed events set forth in the Tax Receivable Agreement, including (i) that ProFrac Holding Corp. has sufficient taxable income to fully utilize the tax benefits covered by the Tax Receivable Agreement, and (ii) that any ProFrac LLC Units (other than those held by ProFrac Holding Corp.) outstanding on the termination date are deemed to be redeemed on the termination date. Any early termination payment may be made significantly in advance of, and may materially exceed, the actual realization, if any, of the future tax benefits to which the termination payment relates.

If we experience a change of control (as defined under the Tax Receivable Agreement) or the Tax Receivable Agreement otherwise terminates early, ProFrac Holding Corp.’s obligations under the Tax Receivable Agreement could have a substantial negative impact on our liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, or other forms of business combinations or changes of control. For example, if we were to experience a change of control or the Tax Receivable Agreement was otherwise terminated immediately after this offering, the estimated termination payments would, in the aggregate, be approximately $600 million (calculated using a discount rate equal to (i) the greater of (A) 0.25% and (B) SOFR, plus (ii) 150 basis points, applied against an undiscounted liability of $700 million calculated at the 21% U.S. federal corporate income tax rate and estimated applicable state and local income tax rates). The foregoing amount is merely an estimate and the actual payment could differ materially. There can be no assurance that we will be able to satisfy our obligations under the Tax Receivable Agreement.

Please read “Certain Relationships and Related Party Transactions—Tax Receivable Agreement.”

In the event that payment obligations under the Tax Receivable Agreement are accelerated in connection with certain mergers, other forms of business combinations or other changes of control, the consideration payable to holders of our Class A common stock could be substantially reduced.

If we experience a change of control (as defined under the Tax Receivable Agreement, which includes certain mergers, asset sales and other forms of business combinations), ProFrac Holding Corp. would be obligated to make a substantial immediate lump-sum payment, and such payment may be significantly in advance of, and may materially exceed, the actual realization, if any, of the future tax benefits to which the payment relates. As a result of this payment obligation, holders of our Class A common stock could receive substantially less consideration in connection with a change of control transaction than they would receive in the absence of such obligation. Further, any payment obligations under the Tax Receivable Agreement will not be conditioned upon the TRA Holders’ having a continued interest in ProFrac Holding Corp. or ProFrac LLC. Accordingly, the TRA

 

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Holders’ interests may conflict with those of the holders of our Class A common stock. Please read “Risk Factors—Risks Related to this Offering and Our Class A Common Stock—In certain cases, payments under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits, if any, ProFrac Holding Corp. realizes in respect of the tax attributes subject to the Tax Receivable Agreement” and “Certain Relationships and Related Party Transactions—Tax Receivable Agreement.”

We will not be reimbursed for any payments made under the Tax Receivable Agreement in the event that any tax benefits are subsequently disallowed.

Payments under the Tax Receivable Agreement will be based on the tax reporting positions that we will determine. The U.S. Internal Revenue Service (“IRS”) or another taxing authority may challenge all or part of the tax basis increases covered by the Tax Receivable Agreement, as well as other related tax positions we take, and a court could sustain such challenge. The TRA Holders will not reimburse us for any payments previously made under the Tax Receivable Agreement if any tax benefits that have given rise to payments under the Tax Receivable Agreement are subsequently disallowed, except that excess payments made to any TRA Holder will be netted against future payments that would otherwise be made to such TRA Holder, if any, after our determination of such excess (which determination may be made a number of years following the initial payment and after future payments have been made). As a result, in such circumstances, we could make payments that are greater than ProFrac Holding Corp.’s actual cash tax savings, if any, and we may not be able to recoup those payments, which could materially adversely affect our liquidity.

If ProFrac LLC were to become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes, ProFrac Holding Corp. and ProFrac LLC might be subject to potentially significant tax inefficiencies, and we would not be able to recover payments previously made by ProFrac Holding Corp. under the Tax Receivable Agreement even if the corresponding tax benefits were subsequently determined to have been unavailable due to such status.

We intend to operate such that ProFrac LLC does not become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes. A “publicly traded partnership” is a partnership the interests of which are traded on an established securities market or are readily tradable on a secondary market or the substantial equivalent thereof. Under certain circumstances, redemptions of ProFrac LLC Units pursuant to the Redemption Right (or acquisitions of ProFrac LLC Units pursuant to the Call Right) or other transfers of ProFrac LLC Units could cause ProFrac LLC to be treated as a publicly traded partnership. Applicable U.S. Treasury regulations provide for certain safe harbors from treatment as a publicly traded partnership, and we intend to operate such that redemptions or other transfers of ProFrac LLC Units qualify for one or more such safe harbors. For example, we intend to limit the number of unitholders of ProFrac LLC, and the ProFrac LLC Agreement, which will be entered into in connection with the closing of this offering, will provide for limitations on the ability of unitholders of ProFrac LLC to transfer their ProFrac LLC Units and will provide ProFrac Holding Corp., as the managing member of ProFrac LLC, with the right to impose restrictions (in addition to those already in place) on the ability of unitholders of ProFrac LLC to redeem their ProFrac LLC Units pursuant to the Redemption Right to the extent ProFrac Holding Corp. believes it is necessary to ensure that ProFrac LLC will continue to be treated as a partnership for U.S. federal income tax purposes.

If ProFrac LLC were to become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes, significant tax inefficiencies might result for ProFrac Holding Corp. and for ProFrac LLC, including as a result of ProFrac Holding Corp.’s inability to file a consolidated U.S. federal income tax return with ProFrac LLC. In addition, ProFrac Holding Corp. might not be able to realize tax benefits covered under the Tax Receivable Agreement, and we would not be able to recover any payments previously made by ProFrac Holding Corp. under the Tax Receivable Agreement, even if the corresponding tax benefits (including any claimed increase in the tax basis of ProFrac LLC’s assets) were subsequently determined to have been unavailable.

 

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Changes in effective tax rates, or adverse outcomes resulting from other tax increases or an examination of our income or other tax returns, could adversely affect our results of operations and financial condition.

Any changes in our effective tax rates or tax liabilities could adversely affect our results of operations and financial condition. Our future effective tax rates could be subject to volatility or adversely affected by a number of factors, including:

 

 

changes in the valuation of our deferred tax assets and liabilities;

 

expected timing and amount of the release of any tax valuation allowances;

 

expansion into or future activities in new jurisdictions;

 

the availability of tax deductions, credits, exemptions, refunds and other benefits to reduce tax liabilities;

 

tax effects of share-based compensation; and

 

changes in tax laws, tax regulations, accounting principles, or interpretations or applications thereof.

In addition, an adverse outcome arising from an examination of our income or other tax returns could result in higher tax exposure, penalties, interest or other liabilities that could have an adverse effect on our operating results and financial condition.

We may issue preferred stock whose terms could adversely affect the voting power or value of our Class A common stock.

Our amended and restated certificate of incorporation will authorize us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our Class A common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our Class A common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the Class A common stock.

If we were deemed to be an investment company under the Investment Company Act of 1940, as amended (the “1940 Act”), applicable restrictions could make it impractical for us to continue our business as contemplated and could have a material adverse effect on our business, financial condition and results of operations.

Under Sections 3(a)(1)(A) and (C) of the 1940 Act, a company generally will be deemed to be an “investment company” for purposes of the 1940 Act if (i) it is, or holds itself out as being, engaged primarily, or proposes to engage primarily, in the business of investing, reinvesting or trading in securities or (ii) it engages, or proposes to engage, in the business of investing, reinvesting, owning, holding or trading in securities and it owns or proposes to acquire investment securities having a value exceeding 40% of the value of its total assets (exclusive of U.S. government securities and cash items) on an unconsolidated basis. We do not believe that we are an “investment company,” as such term is defined in either of those sections of the 1940 Act.

As the sole managing member of ProFrac LLC, we will control and operate ProFrac LLC. On that basis, we believe that our interest in ProFrac LLC is not an “investment security” as that term is used in the 1940 Act. However, if we were to cease participation in the management of ProFrac LLC, our interest in ProFrac LLC could be deemed to be an “investment security” for purposes of the 1940 Act.

Although we and ProFrac LLC intend to conduct our operations so that we will not be deemed an investment company, if we were to be deemed an investment company, restrictions imposed by the 1940 Act, including limitations on our capital structure and our ability to transact with affiliates, could make it impractical for us to continue our business as contemplated and could have a material adverse effect on our business, financial condition and results of operations.

 

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We expect to be a “controlled company” within the meaning of the Nasdaq rules and, as a result, will qualify for and intend to rely on exemptions from certain corporate governance requirements.

Because the Wilks will initially own 17,359,338 shares of Class A common stock and 101,586,572 ProFrac LLC Units (and an equal number of shares of Class B common stock), representing approximately 84.8% of the voting power of our Company following the completion of this offering, we expect to be a controlled company as of the completion of the offering under Sarbanes-Oxley and rules of Nasdaq. Additionally, we expect that the Wilks will be deemed a group for purposes of certain rules and regulations of the SEC as a result of the Stockholders’ Agreement. Under the Nasdaq rules, a company of which more than 50% of the voting power is held by another person or group of persons acting together is a controlled company and may elect not to comply with certain Nasdaq corporate governance requirements, including the requirements that:

 

 

a majority of the board of directors consist of independent directors as defined under the rules of Nasdaq;

 

 

the nominating and governance committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and

 

 

the compensation committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities.

These requirements will not apply to us as long as we remain a controlled company. Following this offering, we intend to utilize some or all of these exemptions. Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of Nasdaq. See “Management.”

For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.

We are classified as an “emerging growth company” under the JOBS Act. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things: (i) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of Sarbanes-Oxley; (ii) comply with any new requirements adopted by the Public Company Accounting Oversight Board requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; (iii) provide certain disclosures regarding executive compensation required of larger public companies; or (iv) hold nonbinding advisory votes on executive compensation. Additionally, as an emerging growth company, we are required to have only two years of audited financial statements and only two years of related Management’s Discussion and Analysis of Financial Condition and Results of Operations disclosure. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.07 billion of revenues in a fiscal year, have more than $700.0 million in market value of our Class A common stock held by non-affiliates, or issue more than $1.0 billion of non-convertible debt over a three-year period.

To the extent that we rely on any of the exemptions available to emerging growth companies, you will receive less information about our executive compensation and internal control over financial reporting than issuers that are not emerging growth companies. Additionally, we intend to take advantage of the extended transition periods for the adoption of new or revised financial accounting standards under the JOBS Act until we are no longer an emerging growth company. Our election to use the transition periods permitted by this election may make it difficult to compare our financial statements to those of non-emerging growth companies and other

 

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emerging growth companies that have opted out of the extended transition periods permitted under the JOBS Act and who will comply with new or revised financial accounting standards.

If some investors find our Class A common stock to be less attractive as a result, there may be a less active trading market for our Class A common stock and our stock price may be more volatile.

If securities or industry analysts do not publish research reports or publish unfavorable research about our business, the price and trading volume of our Class A common stock could decline.

The trading market for our Class A common stock will depend in part on the research reports that securities or industry analysts publish about us or our business. We do not currently have and may never obtain research coverage by securities and industry analysts. If no securities or industry analysts commence coverage of us the trading price for our Class A common stock and other securities would be negatively affected. In the event we obtain securities or industry analyst coverage, if one or more of the analysts who covers us downgrades our securities, the price of our securities would likely decline. If one or more of these analysts ceases to cover us or fails to publish regular reports on us, interest in the purchase of our securities could decrease, which could cause the price of our Class A common stock and other securities and their trading volume to decline.

 

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Use of proceeds

We expect to receive approximately $334.6 million of net proceeds (assuming the midpoint of the price range set forth on the cover of this prospectus) from the sale of Class A common stock in this offering, after deducting underwriting discounts and commissions and estimated offering expenses.

We intend to use such net proceeds in the amounts and in the order set forth below:

 

 

$172.2 million of such net proceeds will be used by ProFrac II LLC to make an offer to repay outstanding borrowings under the New Term Loan Credit Facility (which each lender thereunder may accept or reject in its sole discretion) and to pay the related prepayment penalties;

 

 

$22.0 million of such net proceeds will be used by ProFrac LLC to repay amounts outstanding under the Backstop Note;

 

 

$72.9 million of such net proceeds will be used by ProFrac Holding Corp to fund the THRC Equity Purchase;

 

 

$24.7 million of such net proceeds will be used by ProFrac LLC to repay amounts outstanding under the New ABL Credit Facility;

 

 

$22.0 million of such net proceeds will be used by ProFrac LLC to repay amounts outstanding under the Closing Date Note; and

 

 

$20.8 million of such net proceeds will be used by ProFrac LLC to repay amounts outstanding under the Equify Bridge Note.

Our New Term Loan Facility governs how we must apply the net proceeds of this offering. In the event that a lender under the New Term Loan Facility declines an offer of repayment, ProFrac LLC will use such declined net proceeds to make an offer of repayment to other lenders under the New Term Loan Credit Facility. Any net proceeds that are further declined by the lenders shall be retained by ProFrac LLC for use as follows:

 

 

50% of such declined proceeds can be used for general corporate purposes, including the repayment of other indebtedness; and

 

 

50% of such declined proceeds must be used to repay borrowings under the New ABL Credit Facility.

To the extent we are permitted to apply declined net proceeds following an offer of repayment described in the immediately preceding paragraph, we intend to apply such net proceeds to repay indebtedness under the Equify Bridge Facility, the Closing Date Note, the Backstop Note and the New ABL Credit Facility and for general corporate purposes, including the cost of manufacturing additional fleets.

The New Term Loan Credit Facility has a maturity date of March 4, 2025. The average annual interest rate on borrowings under the New Term Loan Credit Facility during the quarter ended March 31, 2022 was 9.5%, and such borrowings were incurred primarily to fund a portion of the purchase price in the FTSI Acquisition and to repay in full and terminate certain outstanding indebtedness and credit facilities of ProFrac LLC and its subsidiaries, which indebtedness was used primarily to fund capital expenditures, including for the build out of our frac fleets. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facilities and Other Financing Arrangements.”

The Equify Bridge Note has a maturity date of March 4, 2027. The average annual interest rate on borrowings under the Equify Bridge Note during the quarter ended March 31, 2022 was 1.0%, and such borrowings were incurred primarily to fund the FTSI Acquisition. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facilities and Other Financing Arrangements.”

 

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The Closing Date Note has a maturity date of March 4, 2027. The average annual interest rate on borrowings under the Closing Date Note during the quarter ended March 31, 2022 was 1.74%, and such borrowings were incurred primarily to fund the FTSI Acquisition. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facilities and Other Financing Arrangements.”

The Backstop Note has a maturity date of March 4, 2027. The average annual interest rate on borrowings under the Backstop Note during the quarter ended March 31, 2022 was 1.74%, and such borrowings were incurred primarily to fund the FTSI Acquisition. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facilities and Other Financing Arrangements.”

The New ABL Credit Facility has a maturity date of the earlier of March 4, 2027 and 91 days prior to the maturity of any material indebtedness (other than the First Financial Loan). The average annual interest rate on borrowings under the New ABL Credit Facility during the quarter ended March 31, 2022 was 4.0%, and such borrowings were incurred primarily to finance the FTSI Acquisition and refinance borrowings outstanding under ProFrac LLC’s prior Old ABL Credit Facility, which borrowings were incurred primarily to fund working capital. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facilities and Other Financing Arrangements.”

The foregoing description does not reflect approximately $1.0 million of proceeds we expect to receive in respect of the par value of the shares of Class B common stock issued in connection with our Corporate Reorganization. We expect to use such net proceeds for general corporate purposes. ProFrac Holding Corp. will contribute all of the net proceeds of this offering to ProFrac LLC in exchange for ProFrac LLC Units (other than proceeds used to fund the THRC Equity Purchase) prior to its use by ProFrac LLC.

A $1.00 increase or decrease in the assumed initial public offering price of $22.50 per share would cause the net proceeds from this offering, after deducting the underwriting discounts and commissions and estimated offering expenses, received by us to increase or decrease, respectively, by approximately $15.0 million, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same. If the proceeds increase due to a higher initial public offering price or due to the issuance of additional shares, we would use the additional net proceeds to reduce outstanding indebtedness. If the proceeds decrease due to a lower initial public offering price or a decrease in the number of shares issued, then we would reduce by a corresponding amount the net proceeds directed to repay indebtedness.

 

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Dividend policy

We do not anticipate declaring or paying any cash dividends to holders of our Class A common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the growth of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon then-existing conditions, including our results of operations, financial condition, capital requirements, investment opportunities, statutory restrictions on our ability to pay dividends and other factors our board of directors may deem relevant. In addition, our existing debt agreements place, and we expect our future debt agreements will place, certain restrictions on our ability to pay cash dividends on our Class A common stock. See “Risk Factors—Risks Related to this Offering and Our Class A Common Stock—We do not intend to pay cash dividends on our Class A common stock and our existing debt agreements place certain restrictions on our ability to do so. Consequently, your only opportunity to achieve a return on your investment is if the price of our Class A common stock appreciates.”

 

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Capitalization

The following table sets forth our cash and cash equivalents and capitalization as of December 31, 2021:

 

 

on an actual basis for ProFrac Predecessor;

 

 

on a pro forma basis to give effect to (i) the expansion of the Old Term Loan Credit Facility and related BPC Acquisition, (ii) the entry into the New Term Loan Credit Facility and the application of borrowings thereunder to fund a portion of the purchase price in the FTSI Acquisition and associated expenses and to repay in full the Old Term Loan Credit Facility, (iii) the issuance of subordinated debt to THRC Holdings and Equify, the proceeds of which were used to fund a portion of the purchase price in the FTSI Acquisition and (iv) the completion of the FTSI Acquisition; and

 

 

on a pro forma as adjusted basis to give effect to (i) the pro forma adjustments described above, (ii) the transactions described under “Corporate Reorganization”, (iii) the sale of shares of our Class A common stock in this offering at the initial offering price of $22.50 per share, after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us and (iv) the application of the net proceeds from this offering as described under “Use of Proceeds.”

The information set forth in the table below is illustrative only and will be adjusted based on the actual initial public offering price and other terms of this offering. This table is derived from, should be read together with and is qualified in its entirety by reference to the historical consolidated financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Corporate Reorganization” and “Use of Proceeds.”

 

   
     As of
December 31, 2021
 
      ProFrac
Predecessor
Historical(1)
     ProFrac
Predecessor
and FTSI
Combined
Pro Forma
   

ProFrac
Holding Corp.
Pro Forma(2)

 
     (in thousands, except share
counts and par value)
 

Cash and cash equivalents

   $ 5,376    $ 59,030   $ 60,085  
  

 

 

    

 

 

   

 

 

 

Long-term debt(3):

       

Old ABL Credit Facility

   $ 69,000    $   $  

New ABL Credit Facility

            69,000       44,342  

First Financial Loan due 2024

     30,000        30,000       30,000  

Old Term Loan Credit Facility due 2023

     171,355               

New Term Loan Credit Facility due 2025

            450,000       281,165  

Best Flow Note

     10,827               

Best Flow Credit Facility

     7,101               

Alpine Promissory Note

     16,717               

Equify Bridge Note due 2027

            34,645       13,845  

Backstop Note due 2027

            22,000        

Closing Date Note due 2027

            22,000        

Other

     1,695        1,695       1,695  

Less: unamortized debt issuance costs

     (5,129      (15,944     (8,968

Less: current portion of long term debt

     (31,793      (14,918     (14,918
  

 

 

 

Total long-term debt

   $ 269,773      $ 598,478     $ 347,161  

Temporary equity

   $      $     $ 2,367,996  

 

 

 

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     As of
December 31, 2021
 
      ProFrac
Predecessor
Historical(1)
     ProFrac
Predecessor
and FTSI
Combined
Pro Forma
    

ProFrac
Holding Corp.
Pro Forma(2)

 
     (in thousands, except share
counts and par value)
 

Members’/Shareholders’ equity:

        

Class A common stock, $0.01 par value; no shares authorized, issued or outstanding (Actual Historical); 600,000,000 shares authorized, 34,991,326 shares issued and outstanding, As Adjusted

                   350  

Class B common stock, $0.01 par value; no shares authorized, issued or outstanding (Actual Historical); 400,000,000 shares authorized, 105,244,274 shares issued and outstanding, As Adjusted

                   1,055  

Members Equity

     147,015        139,212         

Additional paid-in capital

            72,930         

Cumulative translation adjustment

     56        56        56  

Non-controlling interest

     1,039        1,039        1,039  

Retained earnings

                   (1,876,869

Total equity

     148,110        213,237        (1,874,369

Total Capitalization

   $ 417,883      $ 811,715      $ 840,788  

 

 

 

(1)   ProFrac Holding Corp. was incorporated on August 17, 2021. The data in this table has been derived from the historical consolidated financial statements included in this prospectus, which reflect the financial condition and results of operations of ProFrac Predecessor as discussed elsewhere in this prospectus.

 

(2)   A $1.00 increase or decrease in the assumed initial public offering price of $22.50 per share (the midpoint of the rage on the cover page of this prospectus) would increase or decrease total equity and total capitalization by approximately $15.0 million, assuming that the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us. We may also increase or decrease the number of shares we are offering. An increase or decrease of one million shares offered by us at an assumed offering price of $22.50 per share (the midpoint of the range on the cover page of this prospectus) would increase or decrease total equity and total capitalization by approximately $21.0 million, after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

 

(3)   For a description of our long-term debt outstanding as of April 30, 2022, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facilities and Other Financing Arrangements.”.

 

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Dilution

Purchasers of our Class A common stock in this offering will experience immediate and substantial dilution in the net tangible book value (tangible assets less total liabilities) per share of our Class A common stock for accounting purposes. Our net tangible book value as of December 31, 2021, after giving pro forma effect to our Corporate Reorganization, was approximately $148.9 million, or $1.20 per share of Class A common stock.

Pro forma net tangible book value per share is determined by dividing our net tangible book value, or total tangible assets less total liabilities, by our shares of Class A common stock that will be outstanding immediately prior to the closing of this offering. Assuming an initial public offering price of $22.50 per share (which is the midpoint of the price range set forth on the cover page of this prospectus), after giving effect to the sale of the shares in this offering and further assuming the receipt of the estimated net proceeds (after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us and the application of such proceeds as described in the pro forma column in “Capitalization”), our adjusted pro forma net tangible book value as of December 31, 2021 would have been approximately $429.3 million, or $3.06 per share. This represents an immediate increase in the net tangible book value of $1.86 per share to our existing investors and an immediate dilution to new investors purchasing shares in this offering of $19.44 per share, resulting from the difference between the offering price and the pro forma as adjusted net tangible book value after this offering. The following table illustrates the per share dilution to new investors purchasing shares in this offering (assuming that 100% of the ProFrac LLC Units have been exchanged for Class A common stock):

 

Assumed initial public offering price per share

   $ 22.50

Pro forma net tangible book value per share as of December 31, 2021 (before this offering and after giving effect to our Corporate Reorganization)

   $ 1.20

Increase per share attributable to new investors in this offering

   $ 1.86  
  

 

 

 

As adjusted pro forma net tangible book value per share (after giving effect to the Corporate Reorganization and this offering)

   $ 3.06  
  

 

 

 

Dilution in pro forma net tangible book value per share to new investors in this offering(1)

   $ (19.44

 

 

(1)   If the initial public offering price were to increase or decrease by $1.00 per share, then dilution in pro forma net tangible book value per share to new investors in this offering would equal $0.89 or ($0.89), respectively.

The following table summarizes, on an adjusted pro forma basis as of December 31, 2021, the total number of shares of Class A common stock owned by our existing investors (assuming that 100% of the ProFrac LLC Units held by the ProFrac LLC Unit Holders have been exchanged for shares of Class A common stock (and the corresponding shares of Class B common stock have been cancelled)) and to be owned by new investors, the total consideration paid and the average price per share paid by our existing investors and to be paid by new investors in this offering at $22.50 per share, calculated before deduction of estimated underwriting discounts and commissions.

 

       
     Shares acquired      Total consideration      Average
price per
share
 
      Number      Percent      Amount      Percent  
      (in thousands)      (in millions)          

Existing investors

     124,236        88.6%      $ 133.6      27.1%      $ 1.08

New investors in this offering

     16,000        11.4          $ 360.0        72.9            22.50  
  

 

 

 

Total

     140,236        100%      $ 493.6        100%      $ 3.52  

 

 

 

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The data in the table excludes 11,040,000 shares of Class A common stock initially reserved for issuance under our long term incentive plan.

Each $1.00 increase (decrease) in the assumed initial public offering price of $22.50 per share of Class A common stock would increase (decrease) the total consideration paid by new investors in this offering and the total consideration paid by all holders of Class A common stock by approximately $15.0 million, assuming the number of shares of Class A common stock offered by us remains the same, after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

If the underwriters’ option to purchase additional shares is exercised in full, the number of shares of Class A common stock being offered in this offering will be increased to 18,400,000, or approximately 49.6% of the total number of shares of Class A common stock.

 

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Management’s discussion and analysis of financial condition and results of operations

You should read the following discussion and analysis of our financial condition and results of operations together with ProFrac Predecessor’s audited financial statements and related notes thereto appearing at the end of this prospectus. Unless otherwise indicated, the historical financial information in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” reflects only the historical financial results of ProFrac Predecessor prior to the Corporate Reorganization.

Some of the information contained in this discussion and analysis or set forth elsewhere in this prospectus, including information with respect to our plans and strategy for our business and related financing, includes forward-looking statements that involve risks and uncertainties. You should read the sections of this prospectus entitled “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements” for a discussion of important factors that could cause actual results to differ materially from the results described in or implied by the forward-looking statements contained in the following discussion and analysis. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Our Predecessor and ProFrac Holding Corp.

ProFrac Holding Corp. was formed on August 17, 2021, and has not conducted and will not conduct any material business operations prior to the completion of the transactions described under “Corporate Reorganization” other than certain activities related to this offering. Our predecessor consists of ProFrac LLC and its subsidiaries, Best Flow and Alpine (which we refer to as “ProFrac Predecessor”) on a consolidated basis. Historical periods for ProFrac Predecessor had been presented on a consolidated and combined basis given the common control ownership by the Wilks. On December 21, 2021, all of the then-outstanding membership interests in Best Flow and Alpine were contributed to ProFrac LLC in exchange for membership interests in ProFrac LLC. Unless otherwise indicated, the historical consolidated financial information included in this prospectus presents the historical financial information of ProFrac Predecessor. Historical consolidated financial information is not indicative of the results that may be expected in any future periods. For more information, please see the historical consolidated financial statements and related notes thereto included elsewhere in this prospectus and “—Factors Affecting the Comparability of Our Financial Results.”

Overview

We are a growth-oriented, vertically integrated and innovation-driven energy services company providing hydraulic fracturing, completion services and other complementary products and services to leading upstream oil and gas companies engaged in the exploration and production (“E&P”) of North American unconventional oil and natural gas resources. Founded in 2016, ProFrac was built to be the go-to service provider for E&P companies’ most demanding hydraulic fracturing needs. We are focused on employing new technologies to significantly reduce “greenhouse gas” (“GHG”) emissions and increase efficiency in what has historically been an emissions-intensive component of the unconventional E&P development process. We believe the technical and operational capabilities of our fleets ideally position us to capture increased demand resulting from the market recovery and our customers’ shifting preferences favoring the sustainable development of natural resources.

Our operations are primarily focused in the West Texas, East Texas/Louisiana, South Texas, Oklahoma, Uinta and Appalachian regions, where we have cultivated deep and longstanding customer relationships with some of those regions’ most active E&P companies. We operate in three business segments: stimulation services, manufacturing and proppant production. We believe we are the largest privately owned, and second largest

 

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overall, provider of hydraulic fracturing services in North America by HHP, with aggregate installed capacity of over 1.7 million HHP across 34 conventional fleets, of which, as of March 31, 2022, 31 were active, reflecting a net installed capacity of approximately 1.5 million HHP across our active fleets. We believe a greater percentage of our conventional fleets prior to the FTSI Acquisition incorporated lower-emission Tier IV diesel engines relative to our peers, making them among the most emissions-friendly and capable in the industry. Further, we believe that because of those fleets’ capabilities and reliability, and our relentless focus on efficient and environmentally-sound energy service solutions, our high-quality customer base views us as an integral partner in their efforts to improve their ESG profiles without sacrificing service quality.

Our lower-emission conventional hydraulic fracturing fleets have been designed to reduce our customers’ relative emissions footprint while handling the most demanding well completions, which are characterized by higher pumping pressures, higher pumping volumes, longer horizontal wellbores, more frac stages per lateral and increasing amounts of proppant pumped per well. Approximately 90% of our Pre-Acquisition Fleets are less than six years old, with 60% having Tier IV engines and 49% having dual fuel capabilities as of March 31, 2022. In addition, we have paired these technologies with our proprietary ESCs to reduce idle time, which is the time during which an engine generates the highest amount of emissions, by as much as 90%, and reduce fuel consumption and GHG emissions by as much as 24%. In addition, these ESCs are capable of cold starting the engines on our pumping units without the assistance of truck tractors. This technology allows us to significantly decrease the number of truck tractors required for our operations, not only further reducing overall emissions but also eliminating the capital, safety risks and operating and maintenance costs associated with operating the additional truck tractors required for fleets that do not utilize ESCs. On the whole, these cost savings are significant, allowing us to avoid an incremental $15,000 per year in costs associated with each truck tractor eliminated from our operations. Since early 2021, we have installed ESCs in seven fleets, and have reduced our truck tractor count by 125. We continue to install ESCs throughout our fleets, with 141 pumps equipped with ESCs as of March 31, 2022, and anticipate being able to realize total cost savings of approximately $300,000 per year per fleet as a result. When further combined with our real time GHG emissions monitoring, our fleets create additional synergies in efficiency that result in cost savings for our customers. We intend to continue to upgrade and overhaul our other fleets with the goal of having all of our conventional fleets similarly equipped, a process made cheaper by our in-house manufacturing capabilities detailed below. This strategy aligns with our ESG initiative to minimize our carbon footprint as a part of our goal to have all of our conventional fleets equipped with emissions reduction technology. By contrast, many of the fleets we acquired in the FTSI Acquisition are substantially older, are generally less technologically advanced and do not have the same attractive emissions profile as our Pre-Acquisition Fleets. These legacy fleets may require additional maintenance and capital expenditures and may be unable to reduce our customers’ relative emissions footprint or satisfy their ESG objectives. Following the completion of the FTSI Acquisition, approximately 60% of our fleets are less than six years old, with 30% having Tier IV engines and 40% having dual fuel capabilities as of March 31, 2022. After giving effect to our retirement of 650,000 HHP from 11 of FTSI’s older, emissions-intensive fleets acquired in the FTSI Acquisition, 40% of our fleets will have Tier IV engines and 54% of our fleets will have dual fuel capabilities.

In addition to our existing low-emission conventional fleets, we are constructing electric powered hydraulic fracturing fleets equipped with Clean Fleet® technology licensed from USWS. Under our agreement with USWS, we have acquired 3 licenses and may acquire up to 17 additional licenses (along with certain other rights) to construct in-house new, electric-powered hydraulic fracturing fleets utilizing Clean Fleet® technology. This technology utilizes electric motors powered by lower-cost, lower-emission power solutions, including local utility-sourced line power, or on-site generation from natural gas produced and conditioned in the field, CNG, LNG, and/or traditional fuels, if needed. This flexibility in fuel supply can provide our customers with additional tools to meet their emissions and sustainability goals by reducing their reliance on diesel, as well as offer potentially significant fuel cost savings. We believe that our fleets equipped with Clean Fleet® technology will supplement our environmentally advantaged conventional fleets and provide our customers an optimized suite

 

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of options to satisfy their ESG objectives while maximizing operating efficiency. We expect to begin deploying the first of these electric-powered hydraulic fracturing fleets in the second quarter of 2022, and we have two more under construction, which we expect to be ready for deployment during the second half of 2022. We believe that our new electric fleets, together with our existing conventional fleets, which we continue to optimize to incorporate efficiency-enhancing features, place us on the leading edge of the domestic hydraulic fracturing business and position us to maintain a high equipment utilization rate, low emissions and attractive profitability.

Facilitating the advanced technology and operational capability of our equipment is our vertically integrated business model and supply chain management, which allows us to manufacture, assemble, repair and maintain our own fleets and ancillary frac equipment, including power ends, fluid ends, flow iron and monolines. Our vertically integrated business model also allows us to offer customers a suite of ancillary services that enhance the efficacy of the well completion process, including sand, completion chemicals and related equipment.

We operate facilities in Cisco, Aledo and Fort Worth, Texas, including an ISO 9001 2015 certified OEM manufacturing facility, in which we manufacture and refurbish many of the components used by our fleets, including pumps, fluid ends, power ends, flow iron and other consumables and an engine and transmission rebuild facility that is licensed to provide warranty repairs on our transmissions. These facilities, which have a proven capability to manufacture up to 22 pumps, or 55,000 HHP, per month (including electric fleets) and perform substantially all of the maintenance, repair and servicing of our hydraulic fracturing fleets, provide in-house manufacturing capacity that enables cost-advantaged growth and maintenance.

Vertical integration enables us to realize a lower capital investment and operating expense by capturing the margin of manufacturing and/or maintenance, by recycling and refurbishing older machinery in our fleet, as opposed to disposing of it, and by enabling the ongoing improvement of our equipment and processes as part of a continuous research and development cycle. This combination also facilitates our “Acquire, Retire, Replace” approach to growing, maintaining and modernizing our fleets, and helps us mitigate supply chain constraints that have disrupted competitors’ and customers’ operations in the past. For example, as part of the FTSI Acquisition we are implementing our “Acquire, Retire, Replace” strategy by retiring 650,000 HHP of FTSI’s older, emissions-intensive fleets and recycling or refurbishing equipment from such fleets. Our in-house manufacturing capabilities also allow us to rapidly implement new technologies in a cost-effective manner not possible for many of our peers. We believe that as a result of this vertical integration, we are able to achieve conventional Tier IV dual fuel fleet construction costs of $540 per HHP contrasted with an industry cost of up to $861 per HHP, according to Daniel Energy Partners, and an average expected price to build electric fleets, excluding power generation, of $467 per HHP inclusive of licensing costs.

Our manufacturing capabilities and control over the manufacturing process have allowed us to design and build hydraulic fracturing fleets to uniform specifications intended for deployment in resource basins requiring high levels of pressure, flow rate and sand intensity. We believe the standardized, modular configuration of our equipment provides us with several competitive advantages, including reduced repair and maintenance costs, reduced downtime, reduced inventory costs, reduced complexity in our operations, training efficiencies and the ability to redeploy equipment among operating basins. We believe that our uniform fleet specifications along with the ability to more directly control our supply chain and end-of-life management for our equipment differentiates us from competitors who typically purchase such equipment from third party manufacturers and rely on such manufacturers or other third parties for repair and maintenance.    

We also provide ancillary products and services, further increasing our value as a business partner to our customers, including frac sand, completion chemicals, frac design and related services, logistics coordination and real time data reporting, such as operational statistics, inventory management, completions updates and emissions monitoring.

 

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Through our recent convertible preferred equity investment in Flotek, we have gained access to a low-cost, long-term supply of a full suite of completion chemicals required by our customers during the completion process, including Flotek’s proprietary biodegradable complex nano-Fluid® technology, which is more environmentally friendly than commonly used alternatives. For additional information on our investment in Flotek, please see “Summary—Recent Developments—Flotek Investment.”

In addition, to meet our customers’ need for proppant, we operate an approximate three-million-ton-per-year sand mine and processing facility in Kermit, Texas, with 40.7 million tons of proved reserves as of December 31, 2021, which allows us to sell proppant to our customers in West Texas and Southeastern New Mexico. We also recently acquired approximately 6,700 acres near Lamesa, Texas, which we refer to as West Munger, that we are developing into an in-basin Permian Basin frac sand resource. We are in the process of installing mining and processing facilities at West Munger which, once operational, will be one of only two sand mines in the Midland Basin. West Munger and the Kermit sand mine are each located within 100 miles of approximately 98% of all horizontal rigs in the Permian Basin, providing us with ready access to potential customers. Our integrated service platform creates operational efficiencies for our customers and allows us to capture a greater portion of their development capital spending, positioning us to maintain high equipment utilization rates, low emissions and attractive profitability.

For the year ended December 31, 2021, ProFrac Predecessor generated net losses of approximately $43.5 million, Adjusted EBITDA of approximately $134.7 million, Adjusted EBITDA less net capital expenditures of approximately $64.8 million and Adjusted EBITDA per fleet of $9.6 million and, on a pro forma basis, generated net losses of approximately $144.6 million, Adjusted EBITDA of approximately $170.3 million, Adjusted EBITDA less net capital expenditures of approximately $59.6 million and Adjusted EBITDA per fleet of $6.4 million. For the definitions of Adjusted EBITDA, Adjusted EBITDA less net capital expenditures and Adjusted EBITDA per fleet and a reconciliation to their most directly comparable financial measures calculated and presented in accordance with GAAP, please read “—Summary Historical and Pro Forma Financial Data—Non-GAAP Financial Measures.”

Overall trends and outlook

The global public health crisis associated with the COVID-19 pandemic had an unprecedented effect on demand for energy, crude oil prices and global economic activity. In 2020, the combined effect of COVID-19 and the disruptions to the energy industry led to a rapid and significant decline in WTI crude oil prices and Henry Hub natural gas prices, further exacerbating the oilfield service industry conditions still reeling from the broad oil and gas downturn that originally started in 2014. In response to the significant drop in commodity prices, E&P companies acted swiftly to reduce capital budgets and drilling and completion activity. Reduced demand for services compounded by constrained capital access forced the acceleration of the attrition cycle for pressure pumping equipment as older equipment requiring higher repair and maintenance spending were used for spare parts or scrapped in a process that we refer to as cannibalization. Compounding the shrinking effects of cannibalization, several competitors became insolvent and liquidated assets, many of which were sold to overseas markets for use in less demanding well completions activity. Rystad Energy estimates that total HHP capacity has declined by approximately 8.8 million HHP as of Q1 2022 from approximately 25 million HHP at the end of 28, as a result of frac equipment permanently leaving the market as a result of scrapping, cannibalization and deferred maintenance. In addition, approximately 25% of remaining horsepower is comprised of obsolete or non-operational fleets, according to Rystad Energy.

Difficult industry conditions allowed us to strengthen our industry leadership position by implementing targeted and forward-looking initiatives. First, we utilized our in-house repair and maintenance yards to maintain and ensure ongoing operational integrity of our equipment without cannibalization, retaining the quality and reliability of our fleet. Second, we implemented several back-office optimization projects, allowing us to automate processes, increase data accuracy and maintain lower headcount in anticipation of an improving

 

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market. Third, we successfully completed in-house research and development regarding advanced power end and fluid ends designs, leading to substantially longer life of our expendables and reduced repair and maintenance costs. Fourth, we added over 140 dual fuel kits to our Tier IV engines, in order to position ourselves as a market leading provider of low carbon emission solutions. Fifth, we completed the acquisition of EKU, a provider of idle reduction technologies and other equipment engineering and controls that further reduce the carbon footprint of our fleet. Finally, we strategically invested in businesses providing ancillary products and services, such as our investments in West Munger, Flotek and FHE, which provides us with greater supply chain control and mitigates disruptions that have previously impacted the operations of our competitors and customers.

 

Drilling and completion activities for oil and gas are heavily influenced by oil and gas prices. In 2022, geopolitical tensions in Eastern Europe related to Russia’s invasion of Ukraine have resulted in significant supply disruptions as a broad coalition of countries have responded with sanctions and/or import bans associated with Russian oil and natural gas. This has resulted in significant tightening in the market as reflected by higher commodity prices, with oil and gas prices reaching decade highs. We have historically had greater exposure to the gas basins, which yielded superior profitability results and high utilization of our fleets. We have a significant presence in the Haynesville Shale, a high-pressure, high-rate natural gas basin in East Texas and Louisiana, and the northeast’s Marcellus and Utica shales. Natural gas prices have increased substantially compared to year-end 2020 prices and have also surpassed year-end 2019 (pre-COVID-19) levels. Through March 11, 2022, natural gas prices have averaged approximately $4.03/MMBtu over the last twelve months, reflecting an increase of 76% and 72% relative to the twelve months prior to March 11 averages in 2021 and 2020, respectively. Over the long term, EIA expects exports and industrial use will drive natural gas demand. Industrial consumption is expected to increase 25%, or 2.2 Tcf over the next 30 years. Adding to the strong demand outlook for our services in natural gas basins, there are 12.6 bcfpd of existing LNG export facilities in the United States, 3.67 bcfpd of new facilities currently under construction and 25.05 bcfpd of new facilities approved by the Federal Energy Regulatory Commission as of February 2022. As a result of the FTSI Acquisition, our operations have diversified exposure to both natural gas and oil producing areas.

While commodity prices have returned to and exceeded pre-pandemic levels, the pandemic has nonetheless led to supply chain disruptions worldwide. Tariffs, access to employees, increased shipping rates and raw material shortages are plaguing markets. Our supply chain is either vertically integrated or predominantly U.S. based, mitigating our exposure to global disruptions and price increases and allowing us to continue to maintain attractive margins. As our operations are predominantly U.S. based, we have no direct exposure to Russia and Ukraine. We are actively monitoring the broader economic impact of the crisis in Ukraine, especially with respect to rising commodity prices. We have realized indirect impacts that may have occurred as a result of the crisis, such as modest increases in the costs of certain raw materials and components we purchase for use in our manufacturing processes. However, given the inflationary climate in the United States and globally, we are unable to determine the extent to which such increased commodity prices are the result of the crisis in Ukraine or a result of other factors. Despite these increases, we have experienced improved results of operations due to increased utilization of our fleets and increased prices for our products and services which have permitted us to maintain and increase our margins notwithstanding such cost increases. If these disruptions continue, or if there are additional disruptions in our supply chain, it could materially or adversely impact our operating results and financial condition, although we continue to seek to mitigate supply chain disruptions by internalizing processes, such as manufacturing, refurbishment and repair, to the greatest extent possible and by diversifying our suppliers. In response to industry-wide compensation reductions and layoffs, we implemented a variety of programs to help improve employee morale and loyalty during the downturn. The result was minimal turnover of middle to senior management at corporate and district levels, including retaining all district managers. We believe our committed base of employees will allow us to continue providing superior customer service as the industry is exiting the downturn.

The oil and gas industry is currently undergoing significant realignment of operating practices with a focus on reducing impacts to the environment. Many E&P companies are implementing carbon tracking and reduction initiatives and are

 

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expecting oilfield service providers to deliver products and services that utilize the most advanced and environmentally friendly technologies. We believe that companies in the pressure pumping industry with the most technologically advanced fleets and lowest carbon footprint will likely see significant growth in market share at the expense of companies with less advanced equipment. We have embraced tangible initiatives that help to protect the environment and improve our environment and communities making it part of our organizational culture since early in the life of the company. We have and we continue to invest in a number of industry leading advanced technologies that reduce carbon emissions while increasing profitability. Since the company’s inception, we ordered and installed over 245 Tier IV engines for our new-build program. In late 2018, we sold our first fleet, which we originally bought at auction in 2016, due to its inefficiency and high emission profile. In early-2019 we installed our first engine standby controller, which reduces idle in our frac engines and reduces the number of truck tractors we need on location. In mid-2019, we installed our first Tier IV dual fuel system that we developed along with a third party, and we have installed over 199 dual fuel kits since that time. To facilitate our efforts to further reduce fuel consumption in our fleets, in January 2021 we acquired a majority stake in EKU, which manufactures our ESCs. We also co-developed an emissions dashboard for our customers, which has enabled us to accurately track carbon emissions reductions on location. In 2021, we completed the upgrade of a Tier II engine to a Tier IV DGB engine and began field testing. We are currently upgrading five to ten engines per month from Tier II to Tier IV DGB. Finally, in June, 2021 we entered into an agreement with USWS under which we have the ability to acquire up to 20 licenses to construct electric-powered hydraulic fracturing fleets utilizing Clean Fleet® technology. We believe that these initiatives and commitment to lower emissions will help us lead the energy transition of the frac industry towards cleaner and sustainable business.

Our competitors include many large and small oilfield services companies, including Haliburton, Liberty Oilfield Services, ProPetro Holding, NexTier Oilfield Solutions and a number of private locally oriented businesses in each of the basins in which we operate. Competitive factors impacting sales of our services are price, reputation and technical expertise, service and equipment quality, and health and safety standards. Although we believe our customers consider all of these factors, we believe price is a key factor in E&P companies’ criteria in choosing a service provider. While we seek to price our services competitively, we believe many of our customers elect to work with us based on our technological innovation, equipment capability and our commitment to a more ESG-conscious service offering.

How we generate revenue

We operate three business segments: stimulation services, manufacturing and proppant production.

Stimulation services.    We own and operate a fleet of mobile hydraulic fracturing units and other auxiliary equipment that generates revenue by providing stimulation services to our customers. We also provide personnel and services that are tailored to meet each of our customers’ needs. We generally do not have long-term written contractual arrangements with our customers other than standard master service agreements, which include general contractual terms between our customers and us. We charge our customers on a per-job basis, in which we set pricing terms after receiving full specifications for the requested job, including the lateral length of the customer’s wellbore, the number of frac stages per well, the amount of proppant employed and other specifications of the job. Well stimulation contains complementary services that we often provide to our customers, including sand and associated logistics, chemicals and fuel. These complementary services are provided through various contractual arrangements based on our customers’ needs.

Manufacturing.    We primarily generate revenue through sales of highly engineered, tight tolerance machined, assembled, and factory tested products such as high horsepower pumps, valves, piping, swivels, large-bore manifold systems, seats, and fluid ends. As of March 31, 2022, we operate facilities in Cisco, Aledo and Fort Worth, Texas, including an ISO 9001 2015 certified OEM manufacturing facility, in which we manufacture and refurbish many of the components used by our fleets, including pumps, fluid ends, power ends, flow iron and other consumables and an engine and transmission rebuild facility that is licensed to provide warranty repairs on our transmissions. Additionally, we provide iron inspection, iron recertification, pump refurbishment, fluid end refurbishment, pump function testing, paint, scrap, and lube system change services. We charge our customers for equipment based on a per-order basis, in which we set pricing terms after receiving full

 

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specifications for the requested equipment. We charge our customers for our services based on the parts and labor incurred. For the year ended December 31, 2021, approximately 92% of our manufacturing segment’s revenue was intersegment revenue.

Proppant production.    We generate revenue by providing proppant to oilfield service providers and E&P companies. We own and operate the Kermit sand mine in west Texas and recently purchased and are in the process of developing the West Munger sand mine near Lamesa, Texas, and we charge our customers on a per ton of proppant basis at current market prices. We do not have long-term written contractual arrangements with our customers with fixed pricing. For the year ended December 31, 2021, approximately 40%, of our proppant production segment’s revenue was intersegment revenue.

Costs of conducting our business

The principal costs of products and services involved in operating our business are expendables, personnel, equipment repairs and maintenance and fuel. Our fixed costs are relatively low and a large portion of the costs described below are only incurred as we perform jobs for our customers.

Expendables.    Expendables used in our stimulation services business are the largest expenses incurred, and include the fuel, product and freight costs associated with proppant, chemicals and other consumables. Fuel is consumed both in the operation and movement of our hydraulic fracturing fleets and other equipment. In our proppant production business, fuel to run equipment is one of our major expenses. These costs comprise a substantial variable component of our service costs, particularly with respect to the quantity and quality of sand demanded when providing hydraulic fracturing services. Expendable product costs comprised approximately 56% and 53% of total costs of service for the years ended December 31, 2021 and 2020, respectively.

Raw Materials.    Our manufacturing segment relies on various raw materials, specifically various grades of steel and other raw metals, and electricity.

Direct Labor Costs.    Payroll and benefit expenses directly related to the delivery of our products and services are included in our operating costs. Direct labor costs amounted to 18% and 16% of total costs of products and services for the years ended December 31, 2021 and 2020, respectively.

Other Direct Costs.    We incur other expenses related to our products and service offerings, including the costs of repairs and maintenance, general supplies, equipment rental and other miscellaneous operating expenses. Capital expenditures to upgrade or extend the useful life of equipment are not included in other direct costs. Other expenses were 26% and 30% of total costs of products and service for the years ended December 31, 2021 and 2020, respectively.

How we evaluate our operations

Our management uses a variety of financial and operating metrics to evaluate and analyze the performance of our business, including Adjusted EBITDA, Adjusted EBITDA less net capital expenditures and Adjusted EBITDA per fleet.

Note regarding Non-GAAP financial measures

Adjusted EBITDA, Adjusted EBITDA less net capital expenditures and Adjusted EBITDA per fleet

Adjusted EBITDA, Adjusted EBITDA less net capital expenditures and Adjusted EBITDA per fleet are non-GAAP financial measures and should not be considered as substitutes for net income, net loss, operating loss or any other performance measure derived in accordance with GAAP or as an alternative to net cash provided by operating activities as a measure of our profitability or liquidity. Adjusted EBITDA, Adjusted EBITDA less net capital expenditures and Adjusted EBITDA per fleet are supplemental measures utilized by our management

 

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and other users of our financial statements such as investors, commercial banks, research analysts and others, to assess our financial performance because they allow us to compare our operating performance on a consistent basis across periods by removing the effects of our capital structure (such as varying levels of interest expense), asset base (such as depreciation and amortization) and items outside the control of our management team (such as income tax rates).

We view Adjusted EBITDA, Adjusted EBITDA less net capital expenditures and Adjusted EBITDA per fleet as important indicators of performance. We define Adjusted EBITDA as our net income (loss), before (i) interest expense, net, (ii) income tax provision, (iii) depreciation, depletion and amortization, (iv) loss on disposal of assets and (v) other unusual or non-recurring charges, such as costs related to our initial public offering, non-recurring supply commitment charges, certain bad debt expense and gain on extinguishment of debt. We define Adjusted EBITDA less net capital expenditures as Adjusted EBITDA less net capital expenditures plus cash proceeds from sales of assets. We define Adjusted EBITDA per fleet for a particular period as Adjusted EBITDA calculated as a daily average of active fleets during period.

We believe that our presentation of Adjusted EBITDA, Adjusted EBITDA less net capital expenditures and Adjusted EBITDA per fleet will provide useful information to investors in assessing our financial condition and results of operations. In particular, we believe Adjusted EBITDA per fleet allows investors to compare the performance of our fleets across comparable periods and against the fleets of our competitors who may have different capital structures, which may make a fleet-for-fleet comparison more difficult. Net income (loss) is the GAAP measure most directly comparable to Adjusted EBITDA and Adjusted EBITDA less net capital expenditures, and net income (loss) per fleet is the GAAP measure most directly comparable to Adjusted EBITDA per fleet. Adjusted EBITDA and Adjusted EBITDA less net capital expenditures should not be considered as an alternative to net income (loss), and Adjusted EBITDA per fleet should not be considered as an alternative to net income (loss) per fleet. Adjusted EBITDA, Adjusted EBITDA less net capital expenditures and Adjusted EBITDA per fleet have important limitations as analytical tools because they exclude some but not all items that affect the most directly comparable GAAP financial measure. Adjusted EBITDA less net capital expenditures is not necessarily indicative of cash available for discretionary expenditures. You should not consider Adjusted EBITDA, Adjusted EBITDA less net capital expenditures or Adjusted EBITDA per fleet in isolation or as a substitute for an analysis of our results as reported under GAAP. Because Adjusted EBITDA, Adjusted EBITDA less net capital expenditures and Adjusted EBITDA per fleet may be defined differently by other companies in our industry, our definition of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. Please read “Summary—Summary Historical and Pro Forma Financial Data—Non-GAAP Financial Measures.”

Factors affecting the comparability of our financial results

Our future results of operations may not be comparable to our historical results of operations for the reasons described below:

Recent Acquisitions

We have grown recently through strategic acquisitions and investments, including through our recently completed acquisitions of FTSI, FHE and West Munger and our investments in FHE and Flotek. See “Summary—Recent Developments.” These acquisitions are not reflected in our historical results of operations and our future results will differ as a result.

In addition, in connection with our acquisitions, we have recorded the acquired assets and liabilities at fair value on the date of acquisition, which has impacted deferred revenue and deferred costs balances and increased revenue and expenses from that which would have otherwise been recognized in subsequent periods. We also recorded identifiable intangible assets that are amortized over their useful lives, increasing expenses from that which would otherwise have been recognized.

 

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Corporate Reorganization

ProFrac Holding Corp. was incorporated to serve as the issuer in this offering and has no previous operations, assets or liabilities. Following the completion of the Corporate Reorganization, ProFrac LLC, Best Flow and Alpine will be our direct and indirect subsidiaries. As we integrate our operations and further implement controls, processes and infrastructure, it is likely that we will incur incremental selling, general and administrative expenses relative to historical periods.

In addition, ProFrac Holding Corp. will enter into the Tax Receivable Agreement with the TRA Holders. This agreement generally will provide for the payment by ProFrac Holding Corp. to each TRA Holder of 85% of the net cash savings, if any, in U.S. federal, state and local income tax or franchise tax that it actually realizes (or is deemed to realize in certain circumstances) in periods after this offering as a result of (i) certain increases in tax basis that occur as a result of ProFrac Holding Corp.’s acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such TRA Holder’s ProFrac LLC Units in connection with this offering or pursuant to the exercise of the Redemption Right or the Call Right and (ii) imputed interest deemed to be paid by ProFrac Holding Corp. as a result of, and additional tax basis arising from, any payments ProFrac Holding Corp. makes under the Tax Receivable Agreement. ProFrac Holding Corp. will be dependent on ProFrac LLC to make distributions to ProFrac Holding Corp. in an amount sufficient to cover ProFrac Holding Corp.’s obligations under the Tax Receivable Agreement.

Public company expenses

ProFrac Holding Corp. expects to incur additional recurring administrative expenses as a publicly traded corporation that we have not previously incurred, including costs associated with compliance under the Exchange Act, annual and quarterly reports to shareholders, registrar and transfer agent fees, audit fees, incremental director and officer liability insurance costs and director and officer compensation. We additionally expect to incur approximately $2.5 million in incremental, non-recurring costs related to our transition to a publicly traded corporation.

Income taxes

ProFrac Holding Corp. is a corporation and will be subject to U.S. federal, state and local income taxes. Although the ProFrac Predecessor entities are subject to franchise tax in the State of Texas (at less than 1% of modified pre-tax earnings), they have historically been treated as pass-through entities for U.S. federal and other state and local income tax purposes and as such were not subject to U.S. federal income taxes or other state or local income taxes. Rather, the tax liability with respect to the taxable income of the ProFrac Predecessor entities was passed through to their owners. Accordingly, the financial data attributable to ProFrac Predecessor contains no provision for U.S. federal income taxes or income taxes in any state or locality (other than franchise tax in the State of Texas). We estimate that we will be subject to U.S. federal, state and local taxes at a blended statutory rate of approximately 23% of pre-tax earnings.

We account for income taxes under the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled pursuant to the provisions of Accounting Standards Codification (“ASC”) 740, Income Taxes. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized.

We expect to record a full valuation allowance on our net deferred tax assets based on our assessment that it is more likely than not that the deferred tax asset will not be realized. A change in these assumptions could cause a decrease to the valuation allowance, which could materially impact our results of operations.

 

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Results of operations

 

     
    

 

    Year ended
December 31,
 
     

2021

    2020  
     (in thousands, except industry data)  

Revenues—Stimulation services

   $ 745,373     $ 538,282  

Revenues—Manufacturing

     76,360       46,222  

Revenues—Proppant production

     27,225       10,215  

Eliminations

     (80,605     (47,040
  

 

 

 

Total revenues

     768,353       547,679  
  

 

 

 

Cost of revenues, exclusive of depreciation, depletion and amortization—Stimulation services

     570,828       433,122  

Cost of revenues, exclusive of depreciation, depletion, and amortization—Manufacturing

     65,849       40,424  

Cost of revenues, exclusive of depreciation, depletion, and amortization—Proppant production

     14,050       6,064  

Eliminations

     (80,605     (47,040
  

 

 

 

Total cost of revenues, exclusive of depreciation, depletion and amortization

     570,122       432,570  

Depreciation, depletion and amortization

     140,687       150,662  

Loss on disposal of assets, net

     9,777       8,447  

Selling, general and administrative

     65,592       51,014  

Interest expense, net

     25,788       23,276  

Other expense (income)

     111       (324

Income tax (benefit) provision

     (186     582  
  

 

 

 

Net loss

   $ (43,538   $ (118,548

Net loss attributable to noncontrolling interest

     (1,118     (1,143
  

 

 

 

Net loss attributable to ProFrac Predecessor

   $ (42,420   $ (117,405
  

 

 

 

Other data:

    

Adjusted EBITDA—Stimulation services

   $ 122,634     $ 68,787  

Adjusted EBITDA—Manufacturing

   $ 1,382     $ 1,325  

Adjusted EBITDA—Proppant production

   $ 10,672     $ 2,685  

Adjusted EBITDA(1)

   $ 134,688     $ 72,797  

Adjusted EBITDA less net capital expenditures(1)

   $ 64,841     $ 29,440  

Baker Hughes Domestic Average Rig Count—Onshore(2)

     606       524  

Average oil price (per barrel)(3)

   $ 67.99     $ 39.16  

Average natural gas price (per thousand cubic feet)(4)

   $ 3.91     $ 2.03  

 

 

 

(1)   For definitions of the non-GAAP financial measures of Adjusted EBITDA and Adjusted EBITDA less net capital expenditures and reconciliation of Adjusted EBITDA and Adjusted EBITDA less net capital expenditures to our most directly comparable financial measures calculated in accordance with GAAP, please read “Summary—Summary Historical and Pro Forma Financial Data—Non-GAAP Financial Measures.”

 

(2)   Average onshore U.S. rig count published by Baker Hughes.

 

(3)   Average West TX Intermediate Spot Price published by EIA.

 

(4)   Average Henry Hub Natural Gas Spot Price published by EIA.

 

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Year ended December 31, 2021 compared to year ended December 31, 2020

Revenues

Revenues—Stimulation services.    Stimulation services revenues increased 38%, or $207.1 million, to $745.4 million for the year ended December 31, 2021, from $538.3 million for the year ended December 31, 2020. The increase was primarily attributable to strong recovery from the COVID-19 pandemic resulting in an increase in customer activity for our stimulation services. We increased pumping hours 31% for the year ended December 31, 2021, versus the year ended December 31, 2020. Our average marketed active fleet count increased 27% to 14 for the year ended December 31, 2021, from 11 in the year ended December 31, 2020. We define a marketed fleet as 50,000 hydraulic horsepower, three blenders, high pressure iron, one hydration unit, one data van, suction hoses, a manifold system and other ancillary equipment as needed.

Revenues—Manufacturing.    Manufacturing revenues increased 65%, or $30.1 million, to $76.4 million for the year ended December 31, 2021, from $46.2 million for the year ended December 31, 2020. The increase was primarily attributable to an increase in demand for our products due to an increase in commodity prices, demand for manufactured components utilized in the oilfield service industry, and the acquisition of a majority stake in EKU. For the years ended December 31, 2021 and 2020, intersegment revenues accounted for 92% and 97% of manufacturing revenues, respectively.

Revenues—Proppant production.    Proppant production revenues increased 167%, or $17.0 million, to $27.2 million for the year ended December 31, 2021, from $10.2 million for the year ended December 31, 2020. The increase was primarily attributable to a 123% increase in proppant production and a 19% increase in proppant pricing resulting from increases in commodity prices and proppant demand in the Permian basin. The plant operated all 12 months of 2021 as a result of the COVID-19 pandemic recovery compared to 9 months of the same period for 2020. For the years ended December 31, 2021 and 2020, intersegment revenues accounted for 40% and 21% of proppant production revenues, respectively.

Total revenues.     Total revenues increased 40%, or $220.7 million, to $768.4 million for the year ended December 31, 2021, from $547.7 million for the year ended December 31, 2020. The increase was primarily attributable to recovery from the COVID-19 pandemic resulting in increased demand for oilfield services. Average oil and natural gas prices have increased 73% and 92%, respectively, from the year ended December 31, 2021, to the comparative period in 2020. The Baker Hughes U.S. onshore rig count also increased 16% when comparing the same periods.

Operating costs and expenses

Cost of revenues, exclusive of depreciation, depletion, and amortization—Stimulation services.    Cost of revenues, exclusive of depreciation, depletion, and amortization—Stimulation services increased 32%, or $137.7 million, to $570.8 million for the year ended December 31, 2021, from $433.1 million for the year ended December 31, 2020. The increase was primarily due to an increase in fuel, personnel, expendable and other variable costs due to higher activity levels and an increase in our average marketed fleet count from 11 in the year ended December 31, 2020, to 14 in the year ended December 31, 2021. As a percentage of revenues, Cost of revenues, exclusive of depreciation and depletion—Stimulation services was 77% for the year ended December 31, 2021, as compared to 80% for the year ended December 31, 2020.

Cost of revenues, exclusive of depreciation, depletion, and amortization—Manufacturing.    Cost of revenues, exclusive of depreciation, depletion, and amortization—Manufacturing increased 63%, or $25.4 million, to $65.8 million for the year ended December 31, 2021, from $40.4 million for the year ended December 31, 2020. The increase was due to higher activity levels, coupled with higher personnel headcount and our acquisition of

 

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EKU. As a percentage of revenues, Cost of revenues—manufacturing was 86% for the year ended December 31, 2021, as compared to 87% for the year ended December 31, 2020. The decrease in Cost of revenues., exclusive of depreciation and depletion—Manufacturing as a percentage of revenues resulted from a relative increase in power end and fluid end sales, which have a higher margin, compared to flow iron.

Cost of revenues, exclusive of depreciation, depletion, and amortization—Proppant production.    Cost of revenues, exclusive of depreciation, depletion, and amortization—Proppant production increased 131%, or $8.0 million, to $14.1 million for the year ended December 31, 2021, from $6.1 million for the year ended December 31, 2020. The increase was primarily due to a 123% increase in proppant production combined with higher personnel and repairs and maintenance costs resulting from greater market demand and higher activity. As a percentage of revenues, Cost of revenues—Proppant production was 52% for the year ended December 31, 2021, as compared to 59% for the year ended December 31, 2020. The decrease in Cost of revenues, exclusive of depreciation and depletion—Proppant production as a percentage of revenues was primarily attributable to the 19% increase in proppant pricing.

Depreciation, depletion, and amortization.    Depreciation, depletion, and amortization decreased 7%, or $10.0 million, to $140.7 million for the year ended December 31, 2021, from $150.7 million for the year ended December 31, 2020. The decrease was primarily due to fully depreciated high-pressure iron associated with fleets manufactured in 2018 as well as a reduced number of tractor trucks eliminated through our ESC upgrade program.

Loss on disposal of assets, net.    Loss on disposal of assets, net increased 16%, or $1.3 million, to $9.8 million for the year ended December 31, 2021, from $8.4 million for the year ended December 31, 2020. The increase resulted from an increase in the early failure and disposal of components of our pressure pumping equipment as a result of higher activity levels.

Selling, general and administrative.    Selling, general and administrative expenses increased 29%, or $14.6 million, to $65.6 million for the year ended December 31, 2021, from $51.0 million for the year ended December 31, 2020. The increase was due to higher headcount and personnel costs associated with the increased demand of our stimulation services, higher insurance costs due to increased market rates associated with business and medical insurance.

Interest expense, net.    Interest expense, net increased 11%, or $2.5 million, to $25.8 million for the year ended December 31, 2021, from $23.3 million for the year ended December 31, 2020. The increase in interest expense, net was attributable to upsizing our term loan for the purchase of three efrac licenses from USWS.

Other income.    Other expense (income) decreased to $0.1 million for the year ended December 31, 2021 from other income of $0.3 million for the year ended December 31, 2020.

Income tax benefit (provision).    Income tax benefit was $0.2 million for the year ended December 31, 2021 compared to an income tax provision of $0.6 million for the year ended December 31, 2020.

Segment results

The performance of our segments is evaluated primarily on Adjusted EBITDA. For definition of the non-GAAP financial measure of Adjusted EBITDA and reconciliation of Adjusted EBITDA to our most directly comparable financial measures calculated in accordance with GAAP, please read “Summary—Summary Historical and Pro Forma Financial Data—Non-GAAP Financial Measures.”

Adjusted EBITDA—Stimulation services.    Adjusted EBITDA—Stimulation services increased 78%, or $53.8 million, to $122.6 million for the year ended December 31, 2021, from $68.8 million for the year ended December 31, 2020. The increase was primarily attributable to the impacts from the COVID-19 pandemic recovery resulting in an increase in customer activity.

 

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Adjusted EBITDA—Manufacturing.    Adjusted EBITDA—Manufacturing increased 8%, or $0.1 million, to $1.4 million for the year ended December 31, 2021, from $1.3 million for the year ended December 31, 2020.

Adjusted EBITDA—Proppant production.    Adjusted EBITDA—Proppant production increased 297%, or $8.0 million, to $10.7 million for the year ended December 31, 2021, from $2.7 million for the year ended December 31, 2020. The increase was primarily attributable to a 123% increase in proppant production and a 19% increase in proppant pricing resulting from increases in commodity prices and proppant demand in the Permian basin.

Liquidity and capital resources

Historically, our primary sources of liquidity and capital resources have been borrowings under our Old ABL Credit Facility, cash flows from our operations and capital contributions from our shareholders. Our primary uses of capital have been investing in and maintaining our property and equipment and repaying indebtedness.

We expect that our primary sources of liquidity and capital resources after the consummation of this offering will be cash on hand, cash flows generated by operating activities and borrowings under our New ABL Credit Facility. We expect that our primary uses of capital will be to continue to fund our operations, support organic growth opportunities and satisfy future debt payments. Based on our current cash and cash equivalents balance, operating cash flow, availability under our New ABL Credit Facility and the ongoing actions discussed above, we believe that we will be able to maintain sufficient liquidity to fund our planned capital expenditures, satisfy our obligations and remain in compliance with our existing debt covenants through the next twelve months and beyond.

Following the consummation of this offering, ProFrac Holding Corp. will be obligated to make payments under the Tax Receivable Agreement. The actual timing and amount of any payments that may be made under the Tax Receivable Agreement are unknown at this time and will vary based on a number of factors. For more information about these factors, see “Certain Relationships and Related Party Transactions—Tax Receivable Agreement.” However, we expect that the payments that ProFrac Holding Corp. will be required to make to the TRA Holders in connection with the Tax Receivable Agreement will be substantial. Any payments made by ProFrac Holding Corp. to the TRA Holders under the Tax Receivable Agreement will generally reduce the amount of cash that might have otherwise been available to ProFrac Holding Corp. or ProFrac LLC. To the extent ProFrac LLC has available cash, and subject to the terms of any current or future debt instruments, the ProFrac LLC Agreement will require ProFrac LLC to make pro rata cash distributions to the holders of ProFrac LLC Units, including ProFrac Holding Corp., in an amount at least sufficient to allow ProFrac Holding Corp. to pay its taxes and to make payments under the Tax Receivable Agreement. We generally expect ProFrac LLC to fund such distributions out of available cash. However, except in cases where we elect to terminate the Tax Receivable Agreement early, the Tax Receivable Agreement is terminated early due to certain mergers or other changes of control or ProFrac Holding Corp. has available cash but fails to make payments when due, generally ProFrac Holding Corp. may elect to defer payments due under the Tax Receivable Agreement if it does not have available cash to satisfy its payment obligations under the Tax Receivable Agreement or if our contractual obligations limit its ability to make these payments. Any such deferred payments under the Tax Receivable Agreement generally will accrue interest at the rate provided for in the Tax Receivable Agreement, and such interest may significantly exceed our other costs of capital. In certain circumstances (including but not limited to an early termination of the Tax Receivable Agreement due to a change of control or otherwise), payments under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits, if any, ProFrac Holding Corp. realizes in respect of the tax attributes subject to the Tax Receivable Agreement. In the case of such an acceleration in connection with a change of control, where applicable, we generally expect the accelerated payments due under the Tax Receivable Agreement to be funded out of the proceeds of the change of control transaction giving rise to such acceleration, which could have a significant impact on our ability to consummate a change of control transaction or could result in substantially less proceeds being received by our

 

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shareholders in connection with such change of control compared to what they would receive in the absence of the Tax Receivable Agreement obligation. However, we may be required to fund such payment from other sources, and, as a result, any early termination of the Tax Receivable Agreement could have a substantial negative impact on our liquidity or financial condition.

Our 2022 Capital Budget

Our 2022 capital expenditure budget, excluding acquisitions, is estimated to be in a range between $240 million and $290 million. We have budgeted approximately $65 million to $70 million to construct three electric-powered fleets. We are fully committed to building the three electric-powered fleets and have several customers interested in contracting these fleets. We intend to align fleet construction and other growth capital expenditures with visible customer demand, by strategically deploying new equipment in response to inbound customer requests and industry trends. Also included in our 2022 capital expenditure budget is $25 million to $30 million to construct the West Munger sand mine. The remainder of our 2022 capital expenditure budget, excluding acquisitions, will be used to fund maintenance capital expenditures, estimated to be $2.75 million to $3.0 million per fleet per year, and other growth initiatives such as upgrading Tier II fleets to Tier IV dual fuel fleets. We continually evaluate our capital expenditures and the amount that we ultimately spend will depend on a number of factors, including customer demand for new fleets and expected industry activity levels. We believe we will be able to fund our 2022 capital program from cash flows from operations.

Working Capital

Our working capital deficit was $0.7 million as of December 31, 2021, compared to a working capital deficit of $0.5 million as of December 31, 2020. The $0.2 million decrease in working capital was primarily due to an increase in accounts receivable offset by the West Munger Acquisition and an increase in current portion of long term debt.

Cash and Cash Flows

Our cash and cash equivalents were $5.4 million and $3.0 million at December 31, 2021 and December 31, 2020, respectively.

The following table sets forth the historical cash flows for the years ended December 31, 2021 and 2020:

 

   
     Year ended
December 31,
 
      2021     2020  
     ($ in thousands)  

Net cash provided by operating activities

   $ 43,942     $ 45,054  

Net cash (used in) investing activities

   $ (78,383   $ (44,617

Net cash provided by (used in) financing activities

   $ 36,865     $ (15,322
  

 

 

 

Net increase (decrease) in cash and equivalents

   $ 2,424     $ (14,885

 

 

Operating activities

Net cash provided by operating activities was $43.9 million and $45.1 million for the years ended December 31, 2021 and 2020, respectively. Cash flows from operations were essentially flat year over year. We had a large decrease in net loss, offset by increases in accounts receivable and inventory due to the recovery of the business. The increases in accounts receivable and inventory were offset by smaller increases in accounts payable and accrued expenses.

 

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Investing activities

Net cash used in investing activities was $78.4 million and $44.6 million for the years ended December 31, 2021 and 2020, respectively. The increase was primarily due to higher capital expenditures related to dual fuel engine upgrades, ESC installations and efrac build program.

Financing activities

Net cash provided by financing activities was $36.9 million for the year ended December 31, 2021, compared to net cash used in financing activities of $15.3 million for the year ended December 31, 2020. In 2021, we had net borrowings of debt of $41.3 million, compared to net borrowings of debt of $13.7 million in 2020. The increase in cash provided by financing activities was primarily due to the $40.0 million expansion of our Old Term Loan Credit Facility.

Credit facilities and other financing arrangements

New ABL Credit facility

On March 4, 2022, ProFrac LLC, ProFrac II LLC, as borrower (in such capacity, the “ABL Borrower”), and certain of the ABL Borrower’s wholly owned subsidiaries as obligors, entered into a senior secured asset-based revolving credit agreement (as amended, the “New ABL Credit Facility”), with JPMorgan Chase Bank N.A., as administrative agent and collateral agent (the “ABL Agent”), and the lenders party thereto. The New ABL Credit Facility provides for an asset-based revolving credit facility with a borrowing base and lender commitments of $200 million. The New ABL Credit Facility includes an accordion feature in the amount of $100.0 million. The New ABL Credit Facility has a borrowing base composed of certain eligible accounts receivable and eligible inventory less customary reserves, as redetermined monthly. As of April 30, 2022, the maximum availability under the New ABL Credit Facility as of that date was the aggregate lender commitments of $200.0 million. In addition, on that date, there were $110.7 million of borrowings outstanding and $9.2 million of letters of credit outstanding, resulting in approximately $80.1 million of remaining availability. Our New ABL Credit Facility matures on the earlier of (i) March 4, 2027 and (ii) 91 days prior to the stated maturity of any material indebtedness (other than the First Financial Loan). However, the New ABL Credit Facility provides that the ABL Borrower may request that lenders extend the maturity date of their commitments and loans and that each individual lender shall have the right to consent to such request with respect to its commitments and loans without the consent of any other lender.

Borrowings under the New ABL Credit Facility accrue interest based on a three-tier pricing grid tied to average historical availability, and the ABL Borrower may elect for loans to be based on either an Adjusted Term SOFR or a base rate, plus the applicable margin. The interest rate under our New ABL Credit Facility for (a) Adjusted Term SOFR is the applicable margin plus the fluctuating per annum rate equal to Adjusted Term SOFR (with a an Adjusted Term SOFR Floor of 0.00%); and (b) Base Rate Loans are the applicable margin plus the fluctuating per annum rate equal to the greatest of the Prime Rate in effect on such day, or the NYFRB Rate in effect on such day plus 1/2% of 1% and the Adjusted Term SOFR for a one-month Interest Period as published two (2) U.S. Government Securities Business Days prior to such day (or if such day is not a Business Day, the immediately preceding Business Day), plus 1.0%. The applicable margin for Adjusted Term SOFR Loans ranges from 1.50% to 2.00% and for Base Rate Loans ranges from 0.50% to 1.00%, depending on the average daily availability over the last three months under our New ABL Credit Facility. The New ABL Credit Facility bears a commitment fee ranging from 0.250% to 0.375%, depending on the average daily availability over the last three months payable quarterly in arrears. The New ABL Credit Facility also bears customary letter of credit fees.

 

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Our New ABL Credit Facility is guaranteed by ProFrac LLC and all of the ABL Borrower’s material existing subsidiaries and certain direct and indirect future U.S. restricted subsidiaries of the ABL Borrower. Our New ABL Credit Facility is secured by a lien on, and security interest in, substantially all of each such guarantor’s assets, which consists of:

 

 

a perfected security interest in all present and after-acquired accounts, chattel paper, credit card accounts receivables, deposit accounts, commodity accounts and securities accounts, inventory (other than fracturing equipment), fracturing equipment parts, and, to the extent evidencing, governing, arising from or otherwise related to such items, all documents, general intangibles, instruments, investment property, commercial tort claims, letters of credit, letter-of-credit rights and supporting obligations, and the proceeds and products of any of the foregoing and all books, records and documents relating to, or arising from, any of the foregoing, in each case, except to the extent such proceeds constitute Fixed Asset Priority Collateral (as defined under “New Term Loan Credit Facility” below), and subject to customary exceptions and exclusions (collectively, the “ABL Priority Collateral”), which security interest is senior to the security interest in the Fixed Asset Priority Collateral securing the New Term Loan Credit Facility; and

 

 

a perfected security interest in the Fixed Asset Priority Collateral (defined herein), which security interest is junior to the security interest in the foregoing assets securing the New Term Loan Credit Facility.

The respective rights of the New ABL Credit Facility lenders and the Term Loan lenders in the ABL Priority Collateral and the Fixed Asset Priority Collateral are governed by an Intercreditor Agreement among the ABL Agent, the Term Loan Agent (as defined under “New Term Loan Credit Facility” below) and the other parties thereto.

Our New ABL Credit Facility is subject to customary mandatory prepayments, including a mandatory prepayment if the aggregate unpaid principal balance of revolving loans, agent advances, swingline borrowings, unreimbursed drawings under letters of credit and the undrawn amount of outstanding letters of credit exceeds at any time the lesser of (x) the then applicable borrowing base and (y) the then total effective commitments under the New ABL Credit Facility, in an amount equal to such excess. After the occurrence and the continuance of a Cash Dominion Period (defined in the New ABL Credit Facility as (a) any period commencing upon the date that Availability shall have been less than the greater of (i) 12.5% of the Maximum Credit (which is the lesser of the maximum revolver amount in effect at such time and the borrowing base at such time) and (ii) $10.0 million for a period of five consecutive business days and continuing until the date on which availability shall have been at least the greater of (y) 12.5% of the Maximum Credit and (z) $10.0 million for 20 consecutive calendar days or (b) any period commencing on the occurrence of certain specified events of default, and continuing during the period that such specified event of default shall be continuing) and notification thereof by the ABL Agent to the ABL Borrower, all amounts deposited in the concentration account controlled by the ABL Agent will be applied on a daily basis to the outstanding loan balances under the New ABL Credit Facility and certain other secured obligations then due and owing. Voluntary reductions of the unutilized portion of the ABL commitments and prepayments of borrowings under the New ABL Credit Facility are permitted at any time, in specified minimum principal amounts, without premium or penalty, subject to reimbursement of the lenders’ redeployment costs actually incurred in the case of a prepayment of Adjusted Term SOFR borrowings other than on the last day of the relevant interest period.

Our New ABL Credit Facility contains certain customary representations and warranties and affirmative and negative covenants. The negative covenants include, subject to customary exceptions, limitations on indebtedness, dividends, distributions and certain other payments, investments, acquisitions, prepayments of specified junior indebtedness, amendments of specified junior indebtedness, transactions with affiliates, dispositions, mergers and consolidations, liens, restrictive agreements, sale and leaseback transactions, changes in fiscal periods and changes in line of business.

We are required by our New ABL Credit Facility to maintain minimum liquidity of $5.0 million at all times. Additionally, when availability is less than the greater of (i) 12.5% of the maximum credit (which is the lesser of

 

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the maximum revolver amount in effect at such time and the borrowing base at such time) and (ii) $10.0 million and continuing until such time as availability has been in excess of such threshold for a period of 20 consecutive calendar days, we are required by our New ABL Credit Facility to maintain a springing Fixed Charge Coverage Ratio (as defined in our New ABL Credit Facility) of at least 1.0 to 1.0, which is tested quarterly during such period.

Our New ABL Credit Facility contains customary events of default. If an event of default occurs and is continuing, the lenders may declare all loans to be immediately due and payable. Some events of default require an automatic termination of the loans and become immediately due and payable.

New Term Loan Credit Facility

On March 4, 2022, ProFrac LLC, ProFrac II LLC, as borrower (in such capacity, the “Term Loan Borrower”), and certain of the Term Loan Borrower’s wholly owned subsidiaries as obligors, entered into a senior secured term loan credit agreement (the “New Term Loan Credit Facility”), with Piper Sandler Finance LLC, as administrative agent and collateral agent (the “Term Loan Agent”), and the lenders party thereto. The New Term Loan Credit Facility provides for a term loan facility in an aggregate principal amount of $450.0 million. As of April 30, 2022, the Term Loan Borrower had approximately $450.0 million outstanding under the New Term Loan Credit Facility. Our New Term Loan Credit Facility matures on March 4, 2025.

Borrowings under the New Term Loan Credit Facility accrue interest at a percentage per annum equal to (a) until October 1, 2022, (i) for SOFR Rate Loans, 8.50%, and (ii) for Base Rate Loans, 7.50% and (b) thereafter, based on a three-tier pricing grid tied to Total Net Leverage Ratio (as defined in the New Term Loan Credit Facility), and the Term Loan Borrower may elect for loans to be based on either Adjusted Term SOFR or Base Rate, plus the applicable margin. The interest rate on our New Term Loan Credit Facility for (a) SOFR Rate Loans are the applicable margin plus the fluctuating per annum rate equal to Adjusted Term SOFR (as defined in the New Term Loan Credit Facility), with a SOFR floor of 1.00% and (b) Base Rate Loans are the applicable margin plus the fluctuating per annum rate equal to the highest of (i) the federal funds rate plus 1/2 of 1%, (ii) the interest rate quoted in the print edition of The Wall Street Journal, Money Rates Section, as the prime rate in effect, (iii) Adjusted Term SOFR for a one-month interest period as determined on such day, plus 1.0% and (iv) 2.00%.

The applicable margin for (a) SOFR Rate Loans ranges from 6.50% to 8.00% and (b) Base Rate Loans ranges from 5.50% to 7.00%, depending on the Total Net Leverage Ratio (as defined in the New Term Loan Credit Facility) as of the first day of the then-current fiscal quarter.

Our New Term Loan Credit Facility is guaranteed by ProFrac LLC and all of the Term Loan Borrower’s material existing subsidiaries and certain direct and indirect future U.S. restricted subsidiaries of the Term Loan Borrower. Our New Term Loan Credit Facility is secured by a lien on, and security interest in, substantially all of each such guarantor’s assets, which consists of:

 

 

a perfected security interest in all present and after-acquired equipment, fixtures, fracturing equipment (in each case of the foregoing, specifically excluding Fracturing Equipment Parts), real estate, intellectual property, equity interests in all direct and indirect subsidiaries of any grantor, intercompany loans of the grantors and/or their subsidiaries, all other assets whether real, personal or mixed, to the extent not constituting ABL Priority Collateral (as defined under “New ABL Credit Facility” above), and, except to the extent constituting ABL Priority Collateral and to the extent evidencing or otherwise related to such items, all documents, general intangibles, instruments, investment property, commercial tort claims, letters of credit, letter-of-credit rights and supporting obligations, all books, records and documents relating to, or arising from, any of the foregoing, in each case, except to the extent such proceeds constitute ABL Priority Collateral, any fixed asset priority

 

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proceeds account and the proceeds of any of the foregoing, business interruption insurance proceeds and subject to customary exceptions and exclusions (collectively, the “Fixed Asset Priority Collateral”), which security interest is senior to the security interest in the foregoing assets securing the New ABL Credit Facility; and

 

 

a perfected security interest in the ABL Priority Collateral, which security interest is junior to the security interest in the ABL Priority Collateral securing the New ABL Credit Facility.

The respective rights of the New Term Loan Credit Facility lenders and the New ABL Credit Facility lenders in the ABL Priority Collateral and the Fixed Asset Priority Collateral are governed by an intercreditor agreement between the Term Loan Agent and the ABL Agent.

Our New Term Loan Credit Facility is subject to quarterly amortization beginning in June 2022, though any excess cash flow payments, reduce the required amortization.

Additionally, our New Term Loan Credit Facility is subject to a quarterly mandatory prepayment beginning for the calendar quarter ending on September 30, 2022 in an amount equal to the Applicable ECF Percentage (as defined in the New Term Loan Credit Facility). The Applicable ECF Percentage ranges from 50% of Excess Cash Flow (as defined in the New Term Loan Credit Facility) to 25% of Excess Cash Flow depending on the Total Net Leverage Ratio as of the last day of the applicable fiscal quarter. Our New Term Loan Credit Facility is subject to (x) the requirement that the Borrower offer to prepay the Term Loans with certain of the Net Cash Proceeds (as defined in the New Term Loan Credit Facility) from this offering (the “IPO Prepayment”), ranging from 100% of the first $100 million of Net Cash Proceeds, to 0% of the next $100 million of Net Cash Proceeds to 50% of all additional Net Cash Proceeds after that and (y) additional customary mandatory prepayments, subject in some cases referenced in this clause (y) to the right of the Term Loan Borrower and its restricted subsidiaries to reinvest such proceeds within a specified period of time, and certain other exceptions.

Voluntary prepayments of borrowings under the New Term Loan Credit Facility are permitted at any time, in specified minimum principal amounts, subject to reimbursement of the lenders’ redeployment costs actually incurred in the case of a prepayment of SOFR Rate Loans other than on the last day of the relevant interest period. Between March 4, 2022 and March 4, 2023, certain prepayments of the New Term Loan Credit Facility are subject to a prepayment premium of 3.00% (or, in the case of any IPO Prepayment (as defined in the New Term Loan Credit Facility), 2.00%). Between March 5, 2023 and March 4, 2024, certain prepayments of the New Term Loan Credit Facility are subject to a 2.00% prepayment premium. After March 4, 2024, but prior to the Stated Termination Date (as defined in the New Term Loan Credit Facility) certain prepayments of the New Term Loan Credit Facility are subject to a 1.00% prepayment premium. No payment or prepayment premium shall be due on account of any payments or prepayments made on the Stated Termination Date.

Our New Term Loan Credit Facility contains certain customary representations and warranties and affirmative and negative covenants. The negative covenants include, subject to customary exceptions, limitations on indebtedness, dividends, distributions and certain other payments, investments, acquisitions, prepayments of specified junior indebtedness, amendments of specified junior indebtedness, transactions with affiliates, dispositions, mergers and consolidations, liens, restrictive agreements, changes in fiscal periods and changes in line of business.

We are required by our New Term Loan Credit Facility to maintain a Total Net Leverage Ratio (as defined in our New Term Loan Credit Facility) (i) of no more than 2:00 to 1:00 for the fiscal quarter ending on June 30, 2022, (ii) of no more than 1.55 to 1.00 for the fiscal quarters ending on September 30, 2022 and December 31, 2022, and (iii) of no more than 1.25 for each fiscal quarter ending on March 31, 2023 and thereafter.

We are required by our New Term Loan Credit Facility to maintain minimum liquidity of $30.0 million at all times.

 

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Our New Term Loan Credit Agreement prohibits Capital Expenditures (as defined in the New Term Loan Credit Facility) in excess of (i) in the case of the Fiscal Year ended December 31, 2022, the greater of (x) $275,000,000 in the aggregate and (y) in the case of any period of four consecutive fiscal quarters ending in such Fiscal Year, 50% of Consolidated EBITDA for the Test Period most recently ended prior to the date of the applicable Capital Expenditure, and (ii) in the case of any period of four consecutive fiscal quarters ending thereafter, commencing with the period of four consecutive fiscal quarters ending on March 31, 2023, an aggregate amount equal to 50.0% of Consolidated EBITDA for the Test Period most recently ended prior to the date of the applicable Capital Expenditure, provided that if the amount of the Capital Expenditures permitted to be made in any Fiscal Year is greater than the actual amount of the Capital Expenditures actually made in such Fiscal Year, then up to $20,000,000 of such excess amount may be carried forward to the next succeeding Fiscal Year.

Our New Term Loan Credit Facility contains customary events of default. If an event of default occurs and is continuing, the lenders may declare all loans to be immediately due and payable. Some events of default require an automatic termination of the loans and become immediately due and payable.

First Financial Loan

On December 22, 2021, ProFrac II LLC entered into a $30.0 million loan agreement with First Financial Bank, N.A. with a stated maturity date of January 1, 2024 (the “First Financial Loan”). The First Financial Loan bears interest at a variable rate based on the Prime rate published by the Wall Street Journal, floating daily. As of April 30, 2022, ProFrac II LLC had $25.2 million outstanding under the First Financial Loan.

The First Financial Loan is secured by a first lien on, and security interest in, certain truck tractors and all other trailers, trucks and vehicles owned by ProFrac Services and ProFrac Manufacturing, in each case, more particularly described in the security agreement, and is guaranteed by ProFrac Services, ProFrac Manufacturing and ProFrac LLC.

The First Financial Loan is subject to monthly principal amortization beginning in February 2022.

The First Financial Loan contains certain restrictive covenants which require ProFrac LLC to maintain a Total Net Leverage Ratio, as defined in the loan agreement, of no greater than 3.00:1.00, and a Fixed Charge Coverage Ratio, as defined in the loan agreement, of at least 1.00:1.00.

Equify Bridge Note

On March 4, 2022, ProFrac II LLC entered into a $45.8 million subordinated promissory note with Equify Financial with a stated maturity date of March 4, 2027 (the “Equify Bridge Note”). The Equify Bridge Note bears interest at a percentage per annum equal to 1.0%. Interest under the Equify Bridge Note is paid on a quarterly basis and is solely payable in kind, with such interest amounts being added to the outstanding principal amount of the Equify Bridge Note, until the date that both the New ABL Credit Facility and the New Term Loan Credit Facility shall have been terminated, after which date quarterly interest payments may be paid in kind or in cash. In April 2022, the Company repaid $25.0 million in principal under the Equify Bridge Note.

The Equify Bridge Note is unsecured and subordinated to the indebtedness owing under the New ABL Credit Facility and the New Term Loan Credit Facility.

Until the New ABL Credit Facility and the New Term Loan Credit Facility have been terminated, prepayments of principal under the Equify Bridge Note are permitted solely to the extent permitted under the New ABL Credit Facility and New Term Loan Credit Facility. After the New ABL Credit Facility and the New Term Loan Credit Facility have been terminated, prepayments may be made at any time without prepayment penalty or premium.

 

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Backstop Note

On March 4, 2022, ProFrac LLC entered into a $22.0 million subordinated promissory note with THRC Holdings with a stated maturity date of March 4, 2027 (the “Backstop Note”). The Backstop Note bears interest at a percentage per annum equal to 1.74%. Interest under the Backstop Note is paid on a quarterly basis and is solely payable in kind, with such interest amounts being added to the outstanding principal amount of the Backstop Note, until the date that both the New ABL Credit Facility and the New Term Loan Credit Facility shall have been terminated, after which date quarterly interest payments may be paid in kind or in cash.

The Backstop Note is unsecured and subordinated to the indebtedness owing under the New ABL Credit Facility and the New Term Loan Credit Facility.

Until the New ABL Credit Facility and the New Term Loan Credit Facility have been terminated, prepayments of principal under the Backstop Note are permitted solely to the extent permitted under the New ABL Credit Facility and New Term Loan Credit Facility. After the New ABL Credit Facility and the New Term Loan Credit Facility have been terminated, prepayments may be made at any time without prepayment penalty or premium.

Closing Date Note

On March 4, 2022, ProFrac LLC entered into a $22.0 million subordinated promissory note with THRC Holdings with a stated maturity date of March 4, 2027 (the “Closing Date Note”). The Closing Date Note bears interest at a percentage per annum equal to 1.74%. Interest under the Closing Date Note is paid on a quarterly basis and is solely payable in kind, with such interest amounts being added to the outstanding principal amount of the Closing Date Note, until the date that both the New ABL Credit Facility and the New Term Loan Credit Facility shall have been terminated, after which date quarterly interest payments may be paid in kind or in cash.

The Closing Date Note is unsecured and subordinated to the indebtedness owing under the New ABL Credit Facility and the New Term Loan Credit Facility.

Until the New ABL Credit Facility and the New Term Loan Credit Facility have been terminated, prepayments of principal under the Closing Date Note are permitted solely to the extent permitted under the New ABL Credit Facility and New Term Loan Credit Facility. After the New ABL Credit Facility and the New Term Loan Credit Facility have been terminated, prepayments may be made at any time without prepayment penalty or premium.

Contractual obligations

The following table summarizes the principal maturity schedule for our long-term debt outstanding as of December 31, 2021:

 

             
      2022      2023      2024      2025      2026      Thereafter  

ABL Credit Facility(1)

   $      $      $      $      $      $ 69,000  

Term Loan(1)

     16,875        22,500        22,500        109,480                

First Financial loan

     14,110        15,890                              

Best Flow Credit Facility(1)

                                        7,101  

Best Flow Note(1)

                                        10,827  

Alpine Promissory Note(1)

                                        16,717  

Other indebtedness

     808        173        152        101        75        386  
  

 

 

 

Total

   $ 31,793      $ 38,563      $ 22,652      $ 109,581      $ 75      $ 104,031  
(1)   Principal maturity for these facilities reflect the terms of the New ABL Credit Facility, the New Term Loan Credit Facility and the Equify Bridge Loan which refinanced these facilities subsequent to December 31, 2021, however the presented amounts due at maturity in the schedule above are limited by the balances outstanding as of December 31, 2021. Additional detail and a schedule of the full principal repayment obligations as of March 30, 2022 is set forth elsewhere.

 

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Capital expenditures

During the years ended December 31, 2021 and 2020, our capital expenditures were $87.4 million and $48.0 million, respectively. We currently expect our capital expenditures to increase in 2022 and 2023, which are expected to be funded with cash flows from operations. The primary drivers of the increase are building electric-powered hydraulic fracturing fleets, continued engine upgrades as part of our ESG initiatives, and deployment costs associated with reactivating hydraulic fracturing fleets.

Customer concentration

For the year ended December 31, 2021, sales to Rockcliff Energy Management, LLC accounted for 15.4% of total revenue.

On a pro forma basis, Rockcliff in 2021 was greater than 10.1% of pro forma combined revenue and the top ten largest customers contributed to approximately 50.1% of total pro forma combined revenue.

Off-Balance sheet arrangements

From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of December 31, 2021 and December 31, 2020, the off-balance sheet arrangements and transactions that we have entered into include undrawn letters of credit and operating lease

agreements. We do not believe that these arrangements are reasonably likely to materially affect our liquidity or availability of, or requirements for, capital resources.

Quantitative and qualitative disclosure of market risks

Market risk is the risk of loss arising from adverse changes in market rates and prices. Historically, our risks have been predominantly related to potential changes in the fair value of our long-term debt due to fluctuations in applicable market interest rates. Going forward our market risk exposure generally will be limited to those risks that arise in the normal course of business, as we do not engage in speculative, non-operating transactions, nor do we utilize financial instruments or derivative instruments for trading purposes.

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 pressure pumping services such as proppants, chemicals, trucking and fluid supplies. For our manufacturing segment, our material costs primarily include the cost of steel. For our proppant production segment, our material costs primarily include the cost of fuel. Our fuel costs consist primarily of diesel fuel used by our trucks, frac fleets and other motorized equipment. The prices for fuel and the raw materials in our inventory are volatile and are impacted by changes in supply and demand, as well as market uncertainty and regional shortages. Additionally, the market for our products and services is indirectly exposed to fluctuations in the prices of oil and natural gas to the extent such fluctuations impact well completion activity levels. Historically, 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 do not engage in commodity price hedging activities.

Interest rate risk

We are subject to interest rate risk on our variable rate debt. The Company also has fixed rate debt, but does not currently utilize derivative instruments to manage the economic effect of changes in interest rates. The

 

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impact of a 1% increase in interest rates on our outstanding debt as of December 31, 2020 and December 31, 2021 would have resulted in an increase in interest expense of approximately $2.5 million for the year ended December 31, 2020 and $3.7 million for the year ended December 31, 2021.

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 doubtful accounts.

Internal controls and procedures

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes Oxley Act of 2002, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC’s rules implementing Section 302 of Sarbanes-Oxley, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. We will not be required to make our first assessment of our internal control over financial reporting until the year of our second annual report required to be filed with the SEC. To comply with the requirements of being a public company, we may need to implement additional financial and management controls, reporting systems and procedures and hire additional accounting, finance and legal staff.

Further, our independent registered public accounting firm is not yet required to formally attest to the effectiveness of our internal controls over financial reporting, and will not be required to do so for as long as we are an “emerging growth company” pursuant to the provisions of the JOBS Act or a non-accelerated filer. Please read “Summary—Emerging Growth Company Status.”

Recent accounting pronouncements

We have not yet implemented Financial Accounting Standards Board (FASB) Accounting Standards Update (ASU) No. 2016-02, Leases (Topic 842). The ASU introduces a new accounting model for leases, which requires recognition of a right-of-use asset and lease liability on the balance sheet for operating leases. Implementation is not expected to have a material impact on our results of operations, however the Company expects to be required to recognize material assets or liabilities associated with the right to use certain leased assets upon adoption. We are required to adopt Topic 842 using the effective date of January 1, 2022, using the modified retrospective method. Under this adoption method, all leases that are in effect and existence as of, and after the transition date, with a cumulative impact to retained earnings in that period. We expect that this standard will have a material effect on our financial statements. While we continue to assess all the effects of adoption, we currently believe the most significant effects relate to the recognition of new Right of Use (“ROU”) assets and lease liabilities on our balance sheet and providing significant new disclosures about our leasing activities. On adoption, we currently expect to recognize additional operating liabilities of approximately $30.0 million to $40.0 million, with corresponding ROU assets of the same amount based on the present value of the remaining minimum lease payments under current leasing standards for existing operating leases (this excludes ROU assets and operating lease liabilities acquired in the FTSI Acquisition). Additionally, the ROU asset to be recognized upon adoption will increase due to the lease commitments associated with the FTSI Acquisition and the FTSI Sale Leaseback.

We have not yet implemented Financial Accounting Standards Board (FASB) Accounting Standards Update (ASU) No. 2016-13, Financial Instruments—Credit Losses. The ASU introduces a new accounting model, the

 

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Current Expected Credit Losses model (CECL), which requires earlier recognition of credit losses and additional disclosures related to credit risk. The CECL model utilizes a lifetime expected credit loss measurement objective for the recognition of credit losses for loans and other receivables at the time the financial asset is originated or acquired. The expected credit losses are adjusted each period for changes in expected lifetime credit losses. This model replaces the multiple existing impairment models previously used under U.S. GAAP, which generally require that a loss be incurred before it is recognized. The new standard also applies to financial assets arising from revenue transactions such as contract assets and accounts receivable. Implementation of this standard is currently required for fiscal years beginning after December 15, 2022. The Company does not believe implementation will have a material impact on its financial statements.

Emerging growth company

We qualify as an “emerging growth company” pursuant to the provisions of the JOBS Act, enacted on April 5, 2012. Section 102 of the JOBS Act provides that an “emerging growth company” can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards.

We may take advantage of these provisions until we are no longer an emerging growth company, which will occur on the earliest of (i) the last day of the fiscal year following the fifth anniversary of this offering, (ii) the last day of the fiscal year in which we have more than $1.07 billion in annual revenue which, as a result of the FTSI Acquisition, we expect may occur as of December 31, 2022, (iii) the date on which we issue more than $1 billion of non-convertible debt over a three-year period and (iv) the date on which we are deemed to be a “large accelerated filer,” as defined in Rule 12b-2 promulgated under the Exchange Act.

Critical accounting policies and estimates

The discussion and analysis of our financial condition and results of operations is based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally acceptable in the United States of America. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the dates of the financial statements and the reported revenues and expenses during the reporting periods. We evaluate these estimates and assumptions on an ongoing basis and base our estimates on historical experience, current conditions and various other assumptions that we believe to be reasonable under the circumstances. The results of these estimates form the basis for making judgments about the carrying values of assets and liabilities as well as identifying and assessing the accounting treatment with respect to commitments and contingencies. Our actual results may materially differ from these estimates.

Listed below are the accounting policies that we believe are critical to our financial statements due to the degree of uncertainty regarding the estimates or assumptions involved, and that we believe are critical to the understanding of our operations.

Property, plant, and equipment

Our property and equipment are recorded at cost, less accumulated depreciation.

Upon sale or retirement of property and equipment, the cost and related accumulated depreciation are removed from the balance sheet and the net amount, less proceeds from disposal, is recognized as a gain or loss in earnings.

The estimated useful lives and salvage values of property and equipment is subject to key assumptions such as maintenance, utilization and job variation. Unanticipated future changes in these assumptions could negatively

 

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or positively impact our net income. The determination of the appropriate useful life of our property and equipment requires significant judgment resulting from the demanding operating environments in which we conduct our business as well as the significant volatility and demand fluctuations we have seen in our industry in recent years. A significant change in our established useful lives could cause depreciation expenses to fluctuate materially.

Depreciation of property and equipment is provided on the straight-line method over the following estimated useful lives:

 

Machinery and equipment

     2—10 years  

Office equipment, software and other

     3—7 years  

Buildings and leasehold improvements

     2—40 years  

 

 

Impairment of Long-Lived Assets

In accordance with Financial Accounting Standards Board (FASB) ASC 360, Accounting for the Impairment or Disposal of Long-Lived Assets, we review our long-lived assets to be held and used whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future undiscounted cash flows attributable to the assets is less than the carrying amount of such assets. In this circumstance, we recognize an impairment loss for the amount by which the carrying amount of the asset exceeds the fair value of the asset. Our cash flows forecasts require us to make certain judgements regarding long-term forecasts of future revenue and costs and cash flows related to the assets subject to review. Our fair value estimates for certain long-lived assets require us to use significant other observable and unobservable inputs among others including assumptions related to replacement cost based on actual recent auction sales of comparable equipment. The estimates of fair value are also subject to significant variability, are sensitive to changes in market conditions, and are reasonably likely to change in the future. For these reasons, the evaluation of recoverability of our long-lived assets and the measurement of any impairment, as necessary, are considered critical accounting estimates.

Business Combinations

Business combinations are accounted for under the acquisition method of accounting. Under this method, the assets acquired and liabilities assumed are recognized at their respective fair values as of the date of acquisition. The excess, if any, of the acquisition price over the fair values of the assets acquired and liabilities assumed is recorded as goodwill. For significant acquisitions, we utilize third-party appraisal firms to assist us in determining the fair values for certain assets acquired and liabilities assumed. The measurement of these fair values requires us to make significant estimates and assumptions which are inherently uncertain.

Adjustments to the fair values of assets acquired and liabilities assumed are made until we obtain all relevant information regarding the facts and circumstances that existed as of the acquisition date (the “measurement period”), not to exceed one year from the date of the acquisition. We recognize measurement-period adjustments in the period in which we determine the amounts, including the effect on earnings of any amounts we would have recorded in previous periods if the accounting had been completed at the acquisition date.

The estimation of net assets acquired in business combinations requires significant judgment in determination of the fair value of the assets and liabilities acquired. Our fair value estimates require us to use significant observable and unobservable inputs. The estimates of fair value are also subject to significant variability, are sensitive to changes in market conditions, and are reasonably likely to change in the future. A significant change in the observable and unobservable inputs and determination of fair value of the assets and liabilities acquired could significantly impact our consolidated financial statements.

 

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Income Taxes

ProFrac Holding Corp. is a corporation and will be subject to U.S. federal, state and local income taxes. Although the ProFrac Predecessor entities are subject to franchise tax in the State of Texas (at less than 1% of modified pre-tax earnings), they have historically been treated as pass-through entities for U.S. federal and other state and local income tax purposes and as such were not subject to U.S. federal income taxes or other state or local income taxes. Rather, the tax liability with respect to the taxable income of the ProFrac Predecessor entities was passed through to their owners. Accordingly, the financial data attributable to ProFrac Predecessor contains no provision for U.S. federal income taxes or income taxes in any state or locality (other than franchise tax in the State of Texas). We estimate that we will be subject to U.S. federal, state and local taxes at a blended statutory rate of approximately 23% of pre-tax earnings. Additionally, with the acquisition of EKU, the Company is subject to certain foreign taxes, which were immaterial for the year ended December 31, 2021.

We account for income taxes under the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled pursuant to the provisions of Accounting Standards Codification (“ASC”) 740, Income Taxes. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized. We expect to record a full valuation allowance on our net deferred tax assets based on our assessment that it is more likely than not that the deferred tax asset will not be realized. A change in these assumptions could cause a decrease to the valuation allowance, which could materially impact our results of operations.

 

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Industry overview

Demand for hydraulic fracturing services is primarily driven by the level of drilling and completion activity by E&P companies in the United States. Drilling and completion activity is driven by well profitability and returns, which in turn are influenced by a number of factors, including current domestic and international supply and demand for oil and gas and current and expected future prices for oil and gas, as well as the perceived stability and sustainability of those prices over the longer term.

In 2020, the COVID-19 pandemic and disagreements over production levels among oil producing nations combined to cause unprecedented reductions in global economic activity and significantly reduced the demand for oil and gas. These declines led to a significant dip in commodity prices, with per-barrel prices of WTI crude oil briefly falling as low as negative $37/Bbl in April of 2020 and averaging $39/Bbl for the full year 2020, versus $57/Bbl for the full year 2019. In response to the unfavorable price environment, U.S. E&P companies dramatically reduced capital spending, oil and gas drilling and completion activity, and thus, demand for hydraulic fracturing services declined significantly in 2020.

In 2021, economic activity rebounded supported by the COVID-19 vaccination program rollouts and the lifting of mobility restrictions, driving the rapid recovery of global demand for oil and gas despite the occurrence of COVID-19 variants. The per-barrel prices of WTI crude oil averaged $68/Bbl for the full year 2021, an increase of 73% year over year. In 2022, geopolitical tensions in Eastern Europe related to Russia’s invasion of Ukraine have resulted in significant supply disruptions as a broad coalition of countries have responded with sanctions and/or import bans associated with Russian oil and natural gas. This has resulted in significant tightening in the market as reflected by higher commodity prices, with oil and gas prices reaching decade highs. As of March 11, 2022, WTI has averaged $91.60/Bbl in 2022, and the closing price reached as high as $123.70/Bbl on March 8, 2022 following Russia’s invasion of Ukraine. According to EIA, 2022 global crude oil and gas demand is forecast to be around 165.5 MMBoe/d, an increase of 7% relative to 2020 global demand. Oil demand is expected to surpass pre-pandemic levels by the second half of 2022. Demand for natural gas is also expected to grow to support the continued industrialization of developing countries over the coming decades. Fundamental trends shaping the energy transition, including the use of natural gas as a transition fuel, are expected to drive gas to continue gaining global energy demand share.

Global Historical and Projected Oil and Gas Demand

 

LOGO

Source: EIA International Energy Outlook as of October 6, 2021. Includes global liquids and natural gas demand.

Supported by the backdrop of improved global economic growth, U.S. oil and gas consumption is forecasted to increase 8% from 2020 through 2023, according to EIA. U.S. natural gas demand is expected to increase due to use of natural gas as feedstock in domestic petrochemical projects, the growing exports of LNG to international

 

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markets in Europe and Asia, particularly as European countries attempt to reduce their reliance on Russian gas in light of recent geopolitical events, and the addition of gas fired power generation as coal plants are decommissioned.

U.S. Historical and Projected Oil and Gas Demand

LOGO

Source: EIA Short-Term Energy Outlook as of March 8, 2022 for 2017 to 2023P and EIA Annual Energy Outlook as of March 3, 2022 for 2024P. Includes U.S. liquids and natural gas demand.

Natural gas prices have increased substantially compared to year-end 2020 prices and have also surpassed year-end 2019 (pre-COVID-19) levels. Through March 11, 2022, natural gas prices have averaged approximately $4.03/MMBtu over the last twelve months, reflecting an increase of 76% and 72% relative to the twelve months prior to March 11 averages in 2021 and 2020, respectively. Moreover, commodities futures markets as of March 11, 2022 price natural gas contracts at an average of $4.88/MMBtu for the remainder of 2022. Over the longer-term, EIA expects exports and industrial use will continue to drive increased demand for natural gas. If hydrocarbon prices remain at or near current levels, we expect drilling and completion activity to continue to increase, thereby positively impacting demand for our services and improving our revenues and pricing.

With the growth in oil and gas demand and rise in commodity prices, E&P activity has increased significantly across all onshore oil and gas basins in the United States. According to Baker Hughes’ North American Rig Count reported on March 11, 2022, the number of active U.S. land drilling rigs has increased 68% over the last 12 months to 652 rigs and by 182% since its recent trough of 231 rigs in August 2020. Rig activity in our primary areas of operation (the West Texas, East Texas/Louisiana, South Texas, Oklahoma, Uinta and Appalachian regions) has also increased substantially over that same period.

We believe that the following market dynamics and trends in our industry should benefit our operations and our ability to achieve our business objectives as commodity prices recover:

Increased use of horizontal drilling to develop high-pressure U.S. resource basins.    The horizontal rig count as a percentage of the overall onshore rig count has increased every year since 2007, when horizontal rigs represented only approximately 25% of the total U.S. onshore rig count to approximately 90% at the end of 2021. We believe horizontal drilling activity will continue to grow as a portion of overall onshore wells drilled in the United States, primarily due to E&P companies increasingly developing unconventional resources such as shales. Successful economic production of these unconventional resource basins frequently requires hydraulic fracturing services like those we provide.

 

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U.S. Active Horizontal Land Drilling Rigs as a Percent of Active Land Rig Count

 

LOGO

Source: Baker Hughes as of March 11, 2022.

Growth in hydraulic fracturing services.    Hydraulic fracturing is a mission-critical service required for the continued development of shale resources in North America. Demand for hydraulic fracturing fleets is expected to recover materially in 2022 to 265 fleets in the fourth quarter from recent trough levels of 90 fleets in the second quarter of 2020 (an increase of more than 194% across the same period). The rebound in demand for hydraulic fracturing services is expected to continue beyond 2022, with hydraulic fracturing fleets projected to increase from an average of 254 fleets in 2022 to an average of 275 fleets in 2023 (an increase of more than 8%).

U.S. Historical and Projected Frac Fleet Demand

 

LOGO

Source: Daniel Energy Partners as of March 2022.

Increasing completion and pumping intensity.    E&Ps continue to drill longer laterals and increase proppant loadings in order to maximize production and enhance well economics. Longer lateral lengths and greater volume of sand pumped require increased horsepower to execute a completion, which means that more fracturing units will be required for each fleet. Additionally, E&Ps are increasingly adopting zipper frac and simul-fracs techniques, where multiple wells are completed concurrently, in order to improve the efficiency and speed of completion operations. This consequently is driving demand for additional horsepower. We expect that the projected increase in completion intensity trends (as illustrated in the charts below) will result in an increased demand for our pressure pumping services.

 

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U.S. Unconventional Completion Intensity

 

LOGO

Source: Rystad Energy as of February 2022.

U.S. Frac Market Share by Frac Type

 

LOGO

Source: Rystad Energy as of February 2022.

U.S. Land Hydraulic Horsepower Hours per Day per Well

 

LOGO

Source: Rystad Energy. As of February 2022.

Increasing frac intensity per working rig.    Techniques used by E&P companies, such as multi-well pad development programs, have led to improved rig efficiencies, resulting in more horizontal wells drilled per rig.

 

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Coupled with longer laterals, this trend indicates that demand for well completion services as well as frac spend per rig can be expected to outpace standalone rig growth. The co-location of wells on a single pad also allows for more efficient access to wellbores and sharply reduces the mobilization and de-mobilization time between completion and production service jobs. These efficiencies improve our operating leverage and enable us to more successfully provide our services.

 

Total Well Split by Pad Size    Frac Spend per Rig

LOGO

   LOGO

Source: Rystad Energy as of February 2022 for total well split by pad size and Spears & Associates Q4 2021 Hydraulic Fracturing and Proppant Market Report for frac sales per rig.

 

Total U.S. Wells Completed

 

(Total wells)

  

Total U.S. Average Proppant Pumped

 

(thousands of lbs/day)

 

LOGO    LOGO

 

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Total U.S. Average Well Stimulated Length

 

(feet/day)

 

Total U.S. Average Pumping Intensity

 

(Avg. HHP-hrs./well in thousands)

 

LOGO   LOGO

Source: Rystad Energy as of February 2022. Metrics are reflective of total U.S. market.

Tightening Frac Sand Market.    The increase in demand for frac sand for use in the hydraulic fracturing process has resulted in a significant rise in sand prices as well as constraints on supply availability. According to Lium, total U.S. frac sand demand is expected to increase by 31% in 2022 compared to 2021 and reach 117 million tons, with the Permian expected to account for approximately 57% of the total U.S. demand. Frac sand pricing has surpassed pre-COVID levels, with Permian FOB mine pricing reaching as high as $60/ton in the spot market in the first quarter of 2022, according to Lium. We believe our recent investment in West Munger and vertically integrated business model position us to capitalize on this increased demand and insulate our operations from rising sand raw material costs and any potential supply chain disruptions.

Permian Frac Sand Demand Forecast

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Source: Lium Permian Frac Sand Market Trends as of February 2022. Assumes $85/bbl oil price scenario.

 

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In-Basin Permian Sand Pricing Forecast

 

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Source: Lium Permian Frac Sand Market Trends as of February 2022.

Investor and regulator focus on ESG.    The energy industry is undergoing a significant change of operating practices with an emphasis on incorporating more environmental and social considerations into operating models. Companies are experiencing increased market pressure to bolster ESG programs, particularly related to climate change and reduction of GHG emissions. As the regulatory environment becomes more stringent, we believe that state and federal governments are likely to implement increased measures to regulate GHG emissions, increasing pressure on E&P companies to decrease their emissions footprint. Additional ESG topics, such as human rights, supply chain management, water usage, natural capital and biodiversity, among others, are also receiving increased attention, and there may be increasing pressure on our customers to take actions to address these topics, as well.

Adoption of DGB and electric fleets.    We believe E&P operators’ focus on improving their emissions profile will accelerate the transition from legacy, emission-heavy Tier II diesel frac fleets to greener Tier IV DGB frac fleets and electric fleets because Tier IV DGB fleets utilize gas, including natural gas, CNG, LNG, pipeline and field gas, as a cheaper, cleaner fuel source. Rystad Energy anticipates that by the end of 2024, approximately 50-60% of active horsepower in North America will be utilizing natural gas capable fleets. We believe the shift to cleaner natural gas capable fleets positions us well to capture additional market share as the broader industry recovery continues accelerating.

Historical and Projected U.S. Frac Supply by Type

 

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Source: Rystad Energy as of February 2022. Metrics are reflective of total U.S. market.

 

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Obsolescence of significant hydraulic fracturing horsepower in the market.    We believe the U.S. frac market is currently facing a pivotal transition with significant fleet capacity nearing retirement due to obsolescence. We believe that prolonged underinvestment has resulted in an over-supply of legacy fleets and an increasing preference for low-emission fleets is driving an undersupply of more desirable greener frac fleets. Even prior to the COVID-19 induced downturn, substantial legacy capacity had already reached the end of its useful life, according to Rystad Energy. We believe this was further exacerbated by the lack of capital investment by frac operators during the downturn. The majority of frac service providers’ fleets have an average equipment age of more than six years, according to Rystad Energy. We believe that our vertical integration and lower capital cost resulting from our in-house manufacturing of our own frac equipment will benefit our ability to both maintain attractive utilization rates and earn higher returns on invested capital versus other peers that source their new fleets from third parties at higher prices.

U.S. Average Frac Fleet Age

(Number of service providers by average frac equipment age)

 

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Source: Rystad Energy as of March 2022. Metrics are reflective of total U.S. market. Fleet age calculated based on manufacture date for total fleets.

Despite the negative impact to the overall oil and gas industry in 2020, we believe the challenging industry conditions allowed us to strengthen our leadership position by implementing targeted and forward-looking initiatives. We took actions to maintain the ongoing operational integrity of our equipment, further invest in vertical integration of our business, implement back-office optimization projects, successfully complete our in-house research and development of advanced power end and fluid-end designs, and add over 179 dual fuel kits to our Tier IV engines. All of the aforementioned initiatives materially enhanced our company and positioned us to take advantage of expected improving industry conditions.

 

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Business

Overview

We are a growth-oriented, vertically integrated and innovation-driven energy services company providing hydraulic fracturing, completion services and other complementary products and services to leading upstream oil and gas companies engaged in the exploration and production (“E&P”) of North American unconventional oil and natural gas resources. Founded in 2016, ProFrac was built to be the go-to service provider for E&P companies’ most demanding hydraulic fracturing needs. We are focused on employing new technologies to significantly reduce “greenhouse gas” (“GHG”) emissions and increase efficiency in what has historically been an emissions-intensive component of the unconventional E&P development process. We believe the technical and operational capabilities of our fleets ideally position us to capture increased demand resulting from the market recovery and our customers’ shifting preferences favoring the sustainable development of natural resources.

Our operations are primarily focused in the West Texas, East Texas/Louisiana, South Texas, Oklahoma, Uinta and Appalachian regions, where we have cultivated deep and longstanding customer relationships with some of those regions’ most active E&P companies. We operate in three business segments: stimulation services, manufacturing and proppant production. We believe we are the largest privately owned, and second largest overall, provider of hydraulic fracturing services in North America by HHP, with aggregate installed capacity of over 1.7 million HHP across 34 conventional fleets, of which, as of March 31, 2022, 31 were active, reflecting a net installed capacity of approximately 1.5 million HHP across our active fleets. We believe a greater percentage of our conventional fleets prior to the FTSI Acquisition incorporated lower-emission Tier IV diesel engines relative to our peers, making them among the most emissions-friendly and capable in the industry. Further, we believe that because of those fleets’ capabilities and reliability, and our relentless focus on efficient and environmentally-sound energy service solutions, our high-quality customer base views us as an integral partner in their efforts to improve their ESG profiles without sacrificing service quality.

Our lower-emission conventional hydraulic fracturing fleets have been designed to reduce our customers’ relative emissions footprint while handling the most demanding well completions, which are characterized by higher pumping pressures, higher pumping volumes, longer horizontal wellbores, more frac stages per lateral and increasing amounts of proppant pumped per well. Approximately 90% of our Pre-Acquisition Fleets are less than six years old, with 60% having Tier IV engines and 49% having dual fuel capabilities as of March 31, 2022. In addition, we have paired these technologies with our proprietary ESCs to reduce idle time, which is the time during which an engine generates the highest amount of emissions, by as much as 90%, and reduce fuel consumption and GHG emissions by as much as 24%. In addition, these ESCs are capable of cold starting the engines on our pumping units without the assistance of truck tractors. This technology allows us to significantly decrease the number of truck tractors required for our operations, not only further reducing overall emissions but also eliminating the capital, safety risks and operating and maintenance costs associated with operating the additional truck tractors required for fleets that do not utilize ESCs. On the whole, these cost savings are significant, allowing us to avoid an incremental $15,000 per year in costs associated with each truck tractor eliminated from our operations. Since early 2021, we have installed ESCs in seven fleets, and have reduced our truck tractor count by 125. We continue to install ESCs throughout our fleets, with 141 pumps equipped with ESCs as of March 31, 2022, and anticipate being able to realize total cost savings of approximately $300,000 per year per fleet as a result. When further combined with our real time GHG emissions monitoring, our fleets create additional synergies in efficiency that result in cost savings for our customers. We intend to continue to upgrade and overhaul our other fleets with the goal of having all of our conventional fleets similarly equipped, a process made cheaper by our in-house manufacturing capabilities detailed below. This strategy aligns with our ESG initiative to minimize our carbon footprint as a part of our goal to have all of our conventional fleets equipped with emissions reduction technology. By contrast, many of the fleets we acquired in the FTSI Acquisition are substantially older, are generally less technologically advanced and do not have the same attractive emissions profile as our Pre-Acquisition Fleets. These legacy fleets may require additional maintenance and capital expenditures and may be unable to reduce our customers’ relative emissions footprint or satisfy their ESG objectives. Following the completion of the FTSI Acquisition, approximately 60% of our fleets are less than six years

 

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old, with 30% having Tier IV engines and 40% having dual fuel capabilities as of March 31, 2022. After giving effect to our retirement of 650,000 HHP from 11 of FTSI’s older, emissions-intensive fleets acquired in the FTSI Acquisition, 40% of our fleets will have Tier IV engines and 54% of our fleets will have dual fuel capabilities.

In addition to our existing low-emission conventional fleets, we are constructing electric powered hydraulic fracturing fleets equipped with Clean Fleet® technology licensed from USWS. Under our agreement with USWS, we may acquire up to 17 additional licenses (along with certain other rights) to construct in-house new, electric-powered hydraulic fracturing fleets utilizing Clean Fleet® technology. This technology utilizes electric motors powered by lower-cost, lower-emission power solutions, including local utility-sourced line power, or on-site generation from natural gas produced and conditioned in the field, CNG, LNG, and/or traditional fuels, if needed. This flexibility in fuel supply can provide our customers with additional tools to meet their emissions and sustainability goals by reducing their reliance on diesel, as well as offer potentially significant fuel cost savings. We believe that our fleets equipped with Clean Fleet® technology will supplement our environmentally advantaged conventional fleets and provide our customers an optimized suite of options to satisfy their ESG objectives while maximizing operating efficiency. We expect to begin deploying the first of these electric-powered hydraulic fracturing fleets in the second quarter of 2022, and we have two more under construction, which we expect to be ready for deployment during the second half of 2022. We believe that our new electric fleets, together with our existing conventional fleets, which we continue to optimize to incorporate efficiency-enhancing features, place us on the leading edge of the domestic hydraulic fracturing business and position us to maintain a high equipment utilization rate, low emissions and attractive profitability.

Facilitating the advanced technology and operational capability of our equipment is our vertically integrated business model and supply chain management, which allows us to manufacture, assemble, repair and maintain our own fleets and ancillary frac equipment, including power ends, fluid ends, flow iron and monolines. Our vertically integrated business model also allows us to offer customers a suite of ancillary services that enhance the efficacy of the well completion process, including, sand, completion chemicals and related equipment.

We operate facilities in Cisco, Aledo and Fort Worth, Texas, including an ISO 9001 2015 certified OEM manufacturing facility, in which we manufacture and refurbish many of the components used by our fleets, including pumps, fluid ends, power ends, flow iron and other consumables and an engine and transmission rebuild facility that is licensed to provide warranty repairs on our transmissions. These facilities, which have a proven capability to manufacture up to 22 pumps, or 55,000 HHP, per month (including electric fleets) and perform substantially all of the maintenance, repair and servicing of our hydraulic fracturing fleets, provide in-house manufacturing capacity that enables cost-advantaged growth and maintenance.

Vertical integration enables us to realize a lower capital investment and operating expense by capturing the margin of manufacturing and/or maintenance, by recycling and refurbishing older machinery in our fleet, as opposed to disposing of it, and by enabling the ongoing improvement of our equipment and processes as part of a continuous research and development cycle. This combination also facilitates our “Acquire, Retire, Replace” approach to growing, maintaining and modernizing our fleets, and helps us mitigate supply chain constraints that have disrupted competitors’ and customers’ operations in the past. For example, as part of the FTSI Acquisition we are implementing our “Acquire, Retire, Replace” strategy by retiring 650,000 HHP of FTSI’s older, emissions-intensive fleets and recycling or refurbishing equipment from such fleets.

Our in-house manufacturing capabilities also allow us to rapidly implement new technologies in a cost-effective manner not possible for many of our peers. We believe that as a result of this vertical integration, we are able to achieve conventional Tier IV dual fuel fleet construction costs of $540 per HHP contrasted with an industry cost of up to $861 per HHP, according to Daniel Energy Partners, and an average expected price to build electric fleets, excluding power generation, of $467 per HHP inclusive of licensing costs.

 

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Our manufacturing capabilities and control over the manufacturing process have allowed us to design and build hydraulic fracturing fleets to uniform specifications intended for deployment in resource basins requiring high levels of pressure, flow rate and sand intensity. We believe the standardized, modular configuration of our equipment provides us with several competitive advantages, including reduced repair and maintenance costs, reduced downtime, reduced inventory costs, reduced complexity in our operations, training efficiencies and the ability to redeploy equipment among operating basins. We believe that our uniform fleet specifications along with the ability to more directly control our supply chain and end-of-life management for our equipment differentiates us from competitors who typically purchase such equipment from third party manufacturers and rely on such manufacturers or other third parties for repair and maintenance.

We also provide ancillary products and services, further increasing our value as a business partner to our customers, including frac sand, completion chemicals, frac design and related services, logistics coordination and real time data reporting, such as operational statistics, inventory management, completions updates and emissions monitoring.

Through our recent investment in Flotek, we have gained access to a low-cost, long-term supply of a full suite of completion chemicals required by our customers during the completion process, including Flotek’s proprietary biodegradable complex nano-Fluid® technology, which is more environmentally friendly than commonly used alternatives. For additional information on our investment in Flotek, please see “Summary—Recent Developments—Flotek Investment.”

In addition, to meet our customers’ need for proppant, we operate an approximate three-million-ton-per-year sand mine and processing facility in Kermit, Texas, with 40.7 million tons of proved reserves as of December 31, 2021, which allows us to sell proppant to our customers in West Texas and Southeastern New Mexico. We also recently acquired approximately 6,700 acres near Lamesa, Texas, which we refer to as West Munger, that we are developing into an in-basin Permian Basin frac sand resource. We are in the process of installing mining and processing facilities at West Munger which, once operational, will be one of only two sand mines in the Midland Basin. West Munger and the Kermit sand mine are each located within 100 miles of approximately 98% of all horizontal rigs in the Permian Basin, providing us with ready access to potential customers. Our integrated service platform creates operational efficiencies for our customers and allows us to capture a greater portion of their development capital spending, positioning us to maintain high equipment utilization rates, low emissions and attractive profitability.

For the year ended December 31, 2021, ProFrac Predecessor generated net losses of approximately $43.5 million, Adjusted EBITDA of approximately $134.7 million, Adjusted EBITDA less net capital expenditures of approximately $64.8 million and Adjusted EBITDA per fleet of $9.6 million and, on a pro forma basis, generated net losses of approximately $144.6 million, Adjusted EBITDA of approximately $170.3 million, Adjusted EBITDA less net capital expenditures of approximately $59.6 million and Adjusted EBITDA per fleet of $6.4 million. For the definitions of Adjusted EBITDA, Adjusted EBITDA less net capital expenditures and Adjusted EBITDA per fleet and a reconciliation to their most directly comparable financial measures calculated and presented in accordance with GAAP, please read “—Summary Historical and Pro Forma Financial Data—Non-GAAP Financial Measures.”

Competitive strengths

We believe the following characteristics differentiate us from our peers and uniquely position us to execute on our strategy to create value for our stakeholders:

 

 

High performing, technologically advanced fleet focused on cash flow, increased efficiencies, and lower emissions.    We believe we are strongly positioned to continue to respond to the increased demand for highly-efficient and environmentally advantaged energy services, which are those that produce fewer

 

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negative impacts on the environment than those provided by standard Tier II fleets. We believe our Pre-Acquisition Fleet was the largest fleet of low emissions and technologically advanced conventional frac equipment in the United States, with 60% of that fleet equipped with Tier IV engines and 49% with dual fuel capabilities as of March 31, 2022. Following the completion of the FTSI Acquisition, approximately 30% of our fleets are equipped with Tier IV engines and 40% with dual fuel capabilities as of March 31, 2022. While the fleets acquired in the FTSI Acquisition are older, are generally less technologically advanced and do not have the same attractive emissions profile as our Pre-Acquisition Fleets, we have already begun to implement our “Acquire, Retire, Replace” strategy by retiring 650,000 HHP of older, emissions-intensive fleets and recycling or refurbishing equipment from such fleets. These legacy fleets may require additional maintenance and capital expenditures and may be unable to reduce our customers’ relative emissions footprint or satisfy their ESG objectives.

We believe our technologically advanced fleets are among the most reliable and best performing in the industry with the capabilities to meet the most demanding pressure and flow rate requirements in the field. For example, we are one of the few energy services companies to install 60-inch pumps in our fleets, providing for significantly higher capacity and capability. The combination of these factors provides us with an ability to operate efficiently in the most demanding environments while helping our customers meet their ESG goals.

Our standardized equipment reduces our downtime as our mechanics can quickly and efficiently diagnose and repair our equipment and reduces the amount of inventory we need on hand. We are able to easily shift equipment among operating areas as needed to take advantage of market conditions or to replace temporarily damaged equipment. This flexibility allows us to target customers that are offering higher prices for our services, regardless of the basins in which they operate. Standardized equipment also reduces the complexity of our operations, which lowers our training costs and improves our safety profile. Finally, our standardized, high specification equipment, manufacturing capabilities and direct control over significant portions of our supply chain lead to lower total cost of ownership, which we believe allows us to both increase our margins and meet increasing demand for efficient, environmentally-advantaged energy services.

To complement our modern and highly efficient conventional fleets, we expect to begin deploying the first of our electric-powered hydraulic fracturing fleets in the second quarter of 2022, and we have two more under construction, which we expect to be ready for deployment during the second half of 2022. By replacing Tier II diesel engines with electric engines, we expect our fleets equipped with Clean Fleet® technology will reduce carbon emissions by up to 33% per fleet annually. These estimates are based on manufacturer specifications for fuel consumption of each engine configuration and hold constant operational factors that influence the rate of fuel consumption and emissions, such as rate and pressure. This expected reduction is equivalent to a reduction of approximately 1,700 cars on the road per year per fleet based on EPA estimates.

 

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ProFrac Cumulative Pump Configurations & Upgrades by Year:

LOGO

 

(1)   Pre-acquisition fleet mix as of March 31, 2022.

 

 

Vertically integrated business model enhances our ability to meet our customers’ needs.    We operate a vertically integrated business model that includes complementary manufacturing and ancillary products and services, including frac sand, completion chemicals, frac design and data reporting services. Our manufacturing capabilities enhance our profitability through reduced capital and maintenance expenditures, and provides a significant advantage in cost savings and supply chain management versus our peers who do not manufacture and rebuild/refurbish their own equipment and components. Furthermore, we have strategically invested in businesses providing ancillary products and services, such as our investments in West Munger, Flotek and FHE, which provides us with greater supply chain control and mitigates disruptions that have previously impacted the operations of our competitors and customers. We manufacture and refurbish many of the components used by our fleets, including pumps, fluid-ends, power-ends, certain high-pressure iron and other consumables at our facilities located in Cisco, Aledo and Fort Worth, Texas. We have the proven capability to manufacture up to 22 pumps, or 55,000 HHP per month (including electric fleets) and perform substantially all of the maintenance, repair and servicing of our hydraulic fracturing fleets in-house. We also operate an engine and transmission rebuild facility that is licensed to provide warranty repairs on our transmissions.

 

   

“We do the hard jobs.”    Vertical integration of our business enables us to take on premium frac jobs that have more demanding pressure and flow rate requirements that put extra wear and tear on frac equipment and require more frequent equipment rebuilds. We believe many competitors avoid these jobs as they lack the capital or repair capability to sustainably maintain their equipment and generate a reasonable return. At ProFrac, we find such challenging work more economically attractive than less intensive “commodity” work that is easier on equipment because we can be more competitive with higher associated profitability.

 

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Rapid and cost-effective implementation of new technologies.    Much of our equipment is customized for our operations and built with substantially uniform specifications. With our in-house manufacturing capabilities, we are able to rapidly fabricate, develop and deploy new equipment and rebuild/refurbish existing equipment with minimal reliance on third-party supply chains or paying a premium for bespoke orders or processes. In addition to manufacturing our pumping units, we have the capability to manufacture many of the other components of our fleets such as blenders and hydration units. Our manufacturing capabilities facilitated our development of the Centipede high pressure flow system, which reduces non-productive time by reducing rig up time by up to 50% and iron connections by up to 70%, while also preventing shutdowns. We have also developed proprietary vibration monitoring technology that enables our artificial intelligence-driven predictive pre-failure maintenance, performance reporting and design customizations on core equipment. Finally, our preferred equity investment in FHE provides us with access to innovative technology, including its proprietary wellhead pressure control systems, RigLock and FracLock, that enhance well completion efficiency and safety and reduce emissions.

 

   

Advantaged in tight market.    Our vertical integration reduces the risk that we will be unable to source important components, such as fluid-ends, power-ends and other consumable parts and ancillary products and services, such as sand and chemicals. During periods of high demand growth for hydraulic fracturing services, external equipment vendors often report order backlogs of up to nine months, which can lead to increased costs or substantial delays to deploy fleets. The FTSI Acquisition strengthens our in-house repair and manufacturing facilities by increasing our capacity and adding a licensed transmission repair facility. We have historically manufactured all major consumable components and can quickly scale to support all of our fleets at full capacity.

 

   

Insulated from supply chain issues.    Our vertical integration on key completion commodities, such as chemicals and sand, mitigate our exposure to price spikes and supply shortages that have negatively impacted the financial results of some of our competitors during the fourth quarter of 2021 and the first quarter of 2022. We have identified sources of pricing and supply chain risk and have made strategic investments to mitigate them, turning potential weaknesses into strengths. For example, we believe the Flotek investment, through which we monetized our procurement demand, demonstrates our commitment to our vertical integration strategy and provides greater control over our supply chain.

 

 

Organizational culture based on world class service, innovation, safety, improving environmental impact and active contributions to our communities.    We believe our corporate culture plays a significant role in our ability to consistently deliver excellent service to our customers, as well as our ability to attract and retain high quality personnel. We encourage innovation throughout our organization and empower our employees to innovate. For example, we maintain an innovation award program for our employees which provides cash incentives for changes to equipment and processes that improve efficiency and safety. Motivated by this program, our employees have developed numerous tools, processes and equipment enhancements that improve our operations, such as a tool for performing maintenance on fluid ends that reduces the time required for a routine maintenance procedure from 45 minutes to 15 minutes, our PadTrac system that performs live job monitoring and a tool for rebuilding butterfly valves that allows this task to be performed by a single technician. We are committed to the safety and wellness of our employees and we actively foster training, advancement and career development. We also seek to actively contribute our time and resources to positively impact the communities in which we work and live.

 

 

Loyal and active customers that appreciate our efficiency, suite of services and ability to complete the most difficult and demanding projects.    We have a strong portfolio of active customers that value our modern, technologically advanced equipment and our commitment to a more ESG-conscious service offering. As a part of the FTSI Acquisition, our customer base has expanded and diversified to include some of the larger independent exploration and production companies, in addition to our preexisting customer base consisting of leading private midsize operators. We and FTSI had no customer overlap prior to the FTSI Acquisition, resulting in a further diversified customer base in which, as of March 31, 2022, no single customer contracted more than three of our fleets. Our customers trust us to execute on their most technically demanding

 

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operations and value our unique ability to meet their needs with our vertically integrated business model. We believe our operating history combined with our emissions savings equipment and integrated supply chain has us well positioned to serve customers’ needs. While certain of our customers have historically struggled with supply chain disruptions, our business model gives us an opportunity to provide these customers with bundled services, including frac sand, completion chemicals, frac design and related services, logistics and real time data reporting, helping to limit supply chain disruptions. Our track record of consistently providing high-quality, safe and reliable service has enabled us to develop long-term partnerships with our customers, and we expect that our customers will continue to support our growth.

 

 

Strong data and digital capabilities.    Our focus on technology and innovation also underpins our efficiency through real time data analysis of operational statistics, inventory management, completions updates and emissions monitoring. We offer a comprehensive and competitive suite of data and digital solutions such as PadTrac and SOPHIA. PadTrac is a real time data stream that provides pertinent equipment data on location to our operators. SOPHIA is our cloud-based platform that accompanies the ESC and provides visibility into fuel savings and carbon footprint reduction. SOPHIA enhances the credibility, consistency, and transparency of carbon footprint quantification by following ISO standards. We believe our digital infrastructure saves time, money, and makes us a more productive and cost effective enterprise.

 

 

Large scale and leading market share across most active major U.S. basins.    We believe we are the largest privately held hydraulic fracturing provider in North America based on HHP. We operate in some of the most active basins in the United States, including in the West Texas, East Texas/Louisiana, South Texas, Oklahoma, Uinta and Appalachian regions and our operations have diversified exposure to both natural gas and oil producing areas. This geographic and commodity diversity reduces volatility in our revenue due to regional trends, relative commodity prices, adverse weather and other events. Our large footprint and standardized equipment enables us to rapidly reposition our fleets based on demand trends among different regions and allows us to spread our fixed costs over a greater number of fleets. Our large scale also strengthens our negotiating position with our suppliers and our customers. Additionally, we expect to leverage our strengths to capture market share in these regions in response to customer demand for more efficient and cleaner fleets.

 

 

Experienced management and shareholder team that have driven extreme value creation for stakeholders in past endeavors.    Our senior management team has more than 100 years of relevant experience in hydraulic fracturing and the energy industry. The management team is focused on the operational success of the Company and their interests are aligned with those of investors and customers. Additionally, our principal shareholders, the Wilks, have a proven history of founding and growing pressure pumping companies. Prior to founding ProFrac, the Wilks founded FracTech Holdings, LLC, the predecessor to FTSI in 2000, which they grew into one of the largest North American hydraulic fracturing companies based on HHP before selling their 70% interest in that business in 2011 in a transaction that valued the business at approximately $5 billion. The FTSI Acquisition reunites that business with a management team familiar with FTSI’s personnel, culture and equipment and is well suited to execute our “Acquire, Retire, Replace” strategy through strategic cannibalization of FTSI’s older fleets. Combined, the Wilks have more than 75 years’ experience in the energy and energy services sectors. Under their leadership, we have grown our hydraulic fracturing business to a total of 34 fleets, as of March 31, 2022, with an aggregate of over 1.7 million HHP and pro forma 2021 revenues in excess of $1.17 billion. Upon completion of this offering, the Wilks will own approximately     % of our voting stock. We believe that their experience will continue to benefit our operations and business. In addition, Lance Turner, FTSI’s former Chief Financial Officer, became our Chief Financial Officer upon the closing of the FTSI Acquisition. We believe Mr. Turner’s previous experience as Chief Financial Officer of FTSI from October 2015 to March 2022 will further streamline our efforts to efficiently integrate the FTSI business and operations into our business.

 

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Business strategies

We intend to achieve our primary business objective of creating value for our stakeholders through the following business strategies:

 

 

Position ourselves as a key partner to our customers in response to increasing focus on environmental sustainability.    As the demand for energy services in the United States recovers from the lows experienced in 2020, we expect demand for our hydraulic fracturing services to continue to grow significantly. In particular, as one of the largest hydraulic fracturing service providers in North America based on HHP, we believe our modern, technologically advanced fleets position us to capitalize on customer mandates for “next generation” frac fleets due to their lower emissions and the economic benefits of fuel cost savings. We also offer our customers a suite of ancillary products and services that we believe is responsive to our customers’ evolving needs, including frac sand, completion chemicals, frac design, manufacturing and related services, logistics and real time data reporting. Rystad Energy estimates that total HHP capacity has declined by approximately 8.8 million HHP as of Q1 2022 from approximately 25 million HHP at the end of 2018, as a result of frac equipment permanently leaving the market due to scrapping, cannibalization and deferred maintenance. In addition, approximately 25% of remaining horsepower is comprised of obsolete or non-operational fleets, according to Rystad Energy. By contrast, we have focused on upgrading and expanding our fleets’ capabilities and investing in ancillary products and services, and have positioned ourselves as ready to respond to our customers’ needs as upstream activity returns and the focus on ESG-sensitive operations grows. Furthermore, our consistently high fleet utilization levels and 24 hours per day, seven days per week operating schedule should result in greater revenue opportunity and enhanced margins as fixed costs are spread over a broader revenue base. We believe that any incremental future fleet additions will benefit from these trends and associated economies of scale.

 

 

Commitment to returns-driven, environmentally-advantaged investments and technology to support further emissions reduction and greater operational efficiency.    We believe demand for lower emissions operations will outpace current supply and lead to further opportunities to deploy new technical solutions to our customers relative to our competition, particularly with natural gas playing an increasingly critical role in the transition away from less clean sources of energy. We have invested in various businesses and technologies that we plan to leverage to strengthen our market position and to better serve our customers as well as share in the fuel savings provided by our investments. For example, in January 2021, we acquired a 75% ownership stake in EKU, a provider of idle reduction technologies and the manufacturer of our proprietary ESCs. Engines with ESCs will automatically turn off during non-operating time, shutting down the powertrain when it is not pumping and immediately restarting it to full load upon request. This technology reduces the wear and tear on equipment, reduces fuel consumption and eliminates emissions when the engines on our pumping units are automatically turned off and on between stages. A typical frac spread will pump between 14 to 18 hours per day and idle the remaining time. As idle time widely varies between operating stages, most frac companies leave the engines in idle due to the labor-intensive process associated with using the power take-off on a truck tractor to re-start the engine. Based on our own provision of hydraulic fracturing services, we believe our ESCs eliminate roughly 90% of idle hours and result in substantially lower emissions and fuel costs. This reduction in idle time can reduce carbon dioxide emissions by up to 24% compared to standard operations in which engines generally run continuously during a frac job.

Additionally, we are supplementing our already environmentally-advantaged conventional fleets with electric fleets equipped with Clean Fleet® technology, which will provide customers additional low emission and cost effective solutions. We intend to continue this focus on efficiency and emissions-optimized technology in order to capitalize on the increased demand for higher efficiency and higher performing hydraulic fracturing services. We believe that by pursuing the development of advanced technology in both our conventional

 

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fleets and complementary electric-powered fleets, we will be well positioned to capture the increasing demand for highly capable and environmentally-advantaged energy services with which operators may satisfy their ESG imperatives.

We recently acquired West Munger, and made preferred equity investments in Flotek and FHE to enhance our access to products and services necessary during the well completion process in order to mitigate supply chain disruptions and improve our operational efficiencies. Flotek is a market leader in environmentally friendly and biodegradable chemical technologies; FHE is a pioneer in high pressure flow control equipment that is safer and more efficient than legacy industry processes; and West Munger will reduce our trucking distances carrying frac sand for our Permian Basin operations.

 

 

Pursue accretive mix of organic growth and strategic consolidation.    We plan to continue to grow our operations and fleets in response to increased customer demand as well as selectively evaluate potential strategic acquisitions that increase our scale and capabilities and diversify our operations. In response to supply constraints for frac sand, among other factors, we acquired Alpine and West Munger, which we expect to reduce our exposure to supply chain risks and increase our proppant production capacity. We are continuing to evaluate vertical integration of in-basin proppant and logistics opportunities in West Texas and other regions. Similarly, we anticipate that our acquisition of Best will bolster our in-house manufacturing capabilities and will provide access to innovative technology. We believe opportunities exist to acquire older generation diesel frac fleets at attractive prices and use our in-house manufacturing capabilities to upgrade and maintain them, thus extending their useful life and maximizing their cash flow, after which they can be replaced with cutting edge dual fuel or electric technology as part of our “Acquire, Retire, Replace” strategy. We have already begun implementing this strategy with the fleets acquired in the FTSI Acquisition by retiring 650,000 HHP of older FTSI fleets and recycling or refurbishing equipment from such fleets as a source of spare parts and components in our vertically integrated manufacturing segment in connection with selectively upgrading legacy equipment to Tier IV dual fuel engines, increasing efficiency and sustainability. We estimate that FTSI’s existing fleets can be converted to dual fuel capability at a cost of approximately $2.0 million per fleet. The resulting displacement of older fleets should yield significant improvements in emissions, operating efficiency, safety and profitability and provide a source of spare parts and components that can reduce our maintenance capital expenditures. Our vertically integrated business model and in house manufacturing enables faster integration of assets we may acquire and allows us to more economically and efficiently cannibalize, refurbish, and redeploy equipment. Additionally, we expect that our technology and focus on lower emission fleets will promote growth and attract new customers focused on reducing their emissions profiles.

 

 

Continued focus on safe, efficient and reliable operations.    We are an industry leader with a proven track record in safety with a TRIR of 0.42 for the year ended December 31, 2021, including our manufacturing division, compared to the industry average of 0.70, according to the IOGP. We prioritize safety in our equipment through mechanisms like AFEX fire control, which is installed on all of our field equipment and is designed to suppress fires immediately. We believe our excellent safety record is partly attributable to the standardization of our equipment, which makes it easier for mechanics and equipment operators to identify and diagnose problems with equipment before a safety hazard arises. Our fleets are also standardized to use Centipede mono-line, which has fewer iron connections on site and allows for a safer and quicker rig up versus traditional flow iron assemblies. Our streamlined, innovative equipment enables safer operations and time savings, mitigation of inefficiencies from shutdowns, and improvements relative to the amount of horsepower required to put down hole. Additionally, our standardized equipment and in-house manufacturing capability allows us to rapidly assess operations as well as test new equipment while also reducing the complexity of our operations and lowering our training costs.

 

 

Focus on generating superior returns while maintaining a conservative balance sheet and financial policies.    We plan to maintain a conservative balance sheet following this offering, which will allow us to

 

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better react to potential changes in industry and market conditions and opportunistically grow our business. We had $301.3 million of net senior debt, defined as total senior debt of $306.7 million less $5.4 million of cash and equivalents, as of December 31, 2021, and we intend to use a portion of the proceeds from this offering to offer to retire at least $100 million of our senior debt. On a pro forma basis, our net debt as of December 31, 2021 to Adjusted EBITDA for the year ended December 31, 2021 was 1.77. Our 2022 capital expenditure budget, excluding acquisitions, is estimated to be in a range between $240 million and $290 million. We have budgeted approximately $65 million to $70 million to construct three electric-powered fleets. We are fully committed to building the three electric-powered fleets and have several customers interested in contracting these fleets. We intend to align fleet construction and other growth capital expenditures with visible customer demand, by strategically deploying new equipment in response to inbound customer requests and industry trends. Also included in our 2022 capital expenditure budget is $25 million to $30 million to construct the West Munger sand mine. The remainder of our 2022 capital expenditure budget, excluding acquisitions, will be used to fund maintenance capital expenditures, estimated to be $2.75 million to $3.0 million per fleet per year, and other growth initiatives such as upgrading Tier II fleets to Tier IV dual fuel fleets. We continually evaluate our capital expenditures and the amount that we ultimately spend will depend on a number of factors, including customer demand for new fleets and expected industry activity levels. We believe we will be able to fund our 2022 capital program from cash flows from operations. We are disciplined about deploying growth capital to our business, and expect investments in new fleets to have a simple payback of 2.0 years or fewer before investing. As a result of this approach, we believe that we operate one of the most profitable frac businesses and that our strategies and competitive advantages have contributed to our strong relative financial performance, as demonstrated by our history of positive EBITDA generation despite recent market volatility. Our vertical integration of key supply chains enables consistent cost management, low capital intensity and high conversion of EBITDA to cash flow, which we believe will help us deliver shareholder returns across market cycles, while maintaining a conservative balance sheet.

Properties

Our corporate headquarters are located at 333 Shops Boulevard, Suite 301, Willow Park, Texas 76087. We currently own or lease the following additional principal properties:

 

       
Location    Size    Leased or owned    Purpose

Willow Park, TX

   8,244 sqft    Leased    Corporate Headquarters

Smithfield, PA

   47,800 sqft    Leased    Field Operations

Odessa, TX

   21,100 sqft    Leased    Sales Office

Odessa, TX

   50,634 sqft    Leased    Field Operations

Odessa, TX

   82,800 sqft    Owned    Field Operations

Elk City, OK

   42,330 sqft    Owned    Field Operations

Washington County, PA

   41,660 sqft    Owned    Field Operations

Pleasanton, TX

   62,950 sqft    Owned    Field Operations

Longview, TX

   36,000 sqft    Owned    Field Operations

Vernal, UT

   18,827 sqft    Leased    Sales Office

Aledo, TX

   94,050 sqft    Owned    Manufacturing

Hobbs, NM

   12,000 sqft    Leased    Field Operations

Seminole, TX

   33,700 sqft    Leased    Field Operations

Marshall, TX

   21,800 sqft    Leased    Field Operations

Pleasanton, TX

   16,866 sqft    Leased    Field Operations

 

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Location    Size    Leased or owned    Purpose

El Reno, OK

   19,027 sqft    Leased    Field Operations

Dawson County, TX

   6,700 acres    Owned    Raw Land

Winkler County, TX

   641 acres    Owned    Sand Mine

Winkler County, TX

   630 acres    Leased    Sand Mine

Fort Worth, TX

   109,823 sqft    Leased    Manufacturing

Fort Worth, TX

   78,696 sqft    Leased    Manufacturing

Fort Worth, TX

   11,889 sqft    Leased    Manufacturing

Fort Worth, TX

   89,522 sqft    Leased    Manufacturing

Fort Worth, TX

   22,600 sqft    Leased    Corporate Office

Cisco, TX

   130,000 sqft    Owned    Manufacturing

 

We believe that our facilities are adequate for our current operations.

We are seeking to develop the 6,700 acres or raw land in Dawson County, Texas, which we refer to as “West Munger” into a sand mine, and are in the process of installing mining and process facilities, at West Munger. At this time, however, West Munger is an exploration stage property. The approximately 6,700 acre site is located in the Midland Basin near Lamesa, Texas. West Munger and the Kermit sand mine, which is more fully described below, are each located within 100 miles of approximately 98% of all horizontal rigs in the Permian Basin, providing us with ready access to potential customers.

Our mining and processing facilities

We own and operate an approximately three million ton per year sand mine and processing facility located in Winkler County, Texas that we refer to as our “Kermit sand mine.” The total net book value of the Kermit sand mine and its associated plant and equipment was $51.9 million as of December 31, 2021. Our Kermit sand mine facility is located on Farm-to-Market Road (FM) 1218 approximately 14 miles north of Kermit, Texas and approximately 58 miles west of the Midland-Odessa area. The Kermit sand mine is a surface sand mine and a production stage property. Our Kermit sand mine facility features two wash plants and a dry plant with two rotary dryers that clean and classify the sand. We built the facility in 2017 and produce 40/70-mesh and 100-mesh (70/200) sand. Additional onsite facilities include a scale house, office, shop, quality laboratory and onsite housing for up to 40 employees. We believe the Kermit sand mine and its associated plant and equipment are maintained in good working condition. The plant does not crush the material, but cleans and classifies the sand. Once the product is appropriately processed, it is stored in one of eight storage silos until it is transported by truck to its destination.

The Kermit sand mine is serviced by three phase power that is routed along Farm-to-Market Road (FM) 1218, which runs parallel to the western property line. The pipeline providing natural gas supply for the dryers is also routed along this corridor. Plant process water is supplied by 12 wells installed around the periphery of the property. Additionally, water is recycled from the wash process water after fines are removed via settling with a flocculent in a series of constructed ponds. As the mine progresses, silt ponds are constructed in mined-out pits. Wastewater disposal from offices and other buildings are collected via holding tanks and serviced on a regular basis. Potable water is provided by off-site sources (bottled water), although a public water system permit application has been filed.

 

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LOGO

Our production

We produced and sold 1,646,292 tons, 736,726 tons and 1,015,665 tons of frac sand during the years ended December 31, 2021, 2020 and 2019, respectively from the Kermit sand mine.

Our permits

The Kermit sand mine’s current NSR permit is renewable in 2028. Other permits held for such mine include: Stormwater, Above Ground Storage Tank, Aggregate Production Operation, and a Public Water System application (pending). There are no formal state or federal reclamation plans or permits required for the operation.

Our reserves

We believe we have a high-quality mineral reserve base. The SEC has adopted amendments to its disclosure rules to modernize the mineral property disclosure requirements, which are codified in Regulation S-K subpart 1300. This prospectus has been prepared in accordance with the requirements of Subpart 1300 of Regulation S-K, which first became applicable to us for the fiscal year ended December 31, 2021. As used in this prospectus, the terms “mineral reserve” and “proven mineral reserve” are defined and used in accordance with Subpart 1300 of Regulation S-K.

Summary of reserves

We follow Subpart 1300 of Regulation S-K in determining our mineral reserves. Exploration samples are evaluated in our laboratory facilities to assess product quality and mining/processing parameters. Members of

 

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our sales management team assess the salability of the product(s). Geologic, topographic and site data are used to create a geologic model and mining plan. We prepare an analysis of operating costs, capital costs and long-term anticipated sales volume and price to ensure the economic viability of the reserve. To opine as to the economic viability of our mineral reserves, John T. Boyd Company (“John T. Boyd”) reviewed this analysis at the time of the proven reserve determination.

The quantity and nature of the mineral reserves are estimated by our internal mine planning team and third-party companies. According to John T. Boyd, the relatively uniform nature of the sand deposit underlying the property, combined with laboratory testing results, indicate the sand deposit will produce a high-quality proppant sand product that will meet the customer specifications for regional proppant sand within the Permian Basin. Analysis of sand by independent third-party testing companies indicates that the reserves have characteristics which generally meet American Petroleum Institute specifications with regard to crush strength, turbidity and roundness and sphericity. Our internal reserve estimates are provided to John T. Boyd for review annually so that third-party approved additions or reductions can be made to our mineral reserves and mineral resource calculations due to ore extraction, additional drilling and delineation, property acquisitions and dispositions or quality adjustments. Before acquiring new mineral reserves, we perform surveying, drill core analysis and other tests to confirm the quantity and quality of the acquired mineral reserves. John T. Boyd has reviewed our December 31, 2021 mineral reserves, and we intend to continue retaining third-party engineers to review our mineral reserves on an annual basis.

The following tables provide a summary of our Kermit sand mine, which primarily provides proppant for the oil and natural gas industry, as of December 31, 2021 and 2020 based on a price of $19.11(1) per ton:

 

             
                                              As of December 31, 2021  
Mine/plant location   

Owned/

leased

    

Area

(in acres)

    

Proven
reserves

(in thousands
of tons)

    

Probable
reserves

(in thousands
of tons)

     Implied
average
reserve life
(in years)
     Product Size      Recovery*
(%)
 

Winkler County, TX

     Owned        641        27,379        896        26        40/200-Mesh        78  

Winkler County, TX

     Leased        630        13,287        6,288        18        40/200-Mesh        78  

Total

        1,271        40,666        7,184        44        

 

    

 

 

    

 

 

 

 

*   Recovery % represents the overall product yield after mining and processing losses.

 

(1)   The sales price forecast, by product, is based on second quarter of 2021 average prices, and reflects a rebound from 2020 prices. John T. Boyd opines that this is a reasonable price projection.

Based on our proven reserves as of December 31, 2021, and average annual production volume for the three years ended December 31, 2021, our proven sand reserves had an implied average reserve life of more than 44 years.

 

             
                                              As of December 31, 2020  
Mine/plant location   

Owned/

leased

    

Area

(in acres)

    

Proven
reserves

(in thousands
of tons)

    

Probable
reserves

(in thousands
of tons)

     Implied
average
reserve life
(in years)
     Product Size      Recovery*
(%)
 

Winkler County, TX

     Owned        641        29,025        896        27        40/200-Mesh        78  

Winkler County, TX

     Leased        630        13,287        6,288        18        40/200-Mesh        78  

Total

        1,271        42,312        7,184        45        

 

    

 

 

    

 

 

 

 

*   Recovery % represents the overall product yield after mining and processing losses.

 

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Based on our proven reserves as of December 31, 2020, and average annual production volume for the three years ended December 31, 2020, our proven sand reserves had an implied average reserve life of more than 45 years.

The year over year change from December 31, 2020 to December 31, 2021 of approximately 3% in reportable reserve tons is due to the normal mining production activity occurring on the property whereby the run-of-mine material is extracted for the production of saleable frac sand product.

Estimates of in-place frac sand resources for the Kermit sand mine were prepared by performing the following tasks:

 

 

Available drilling logs and laboratory testing results were compiled and reviewed to check for accuracy and to support development of the geologic model. The geologic database utilized for modeling and estimation consists of results from 27 of the 35 holes as 8 holes from the first campaign were twinned by the second campaign for verification purposes. The geologic data were imported into Carlson Software, a geologic modeling and mine planning software suite that is widely used and accepted by the mining industry.

 

 

A geologic model of the deposit was created in Carlson Software using industry-standard grid modeling methods well-suited for simple stratigraphic deposits. The geologic model delineates the top and bottom of the mineable sand horizon and the distribution of the product size fractions across the deposit. The top and bottom of the mineable frac sand interval were established thusly:

 

   

As there is minimal overburden material across the property, the top of the mineable sand interval was defined as the current ground surface as provided by an aerial topographic survey conducted on July 1, 2021.

 

   

The bottom of the mineable sand interval was established by either the bottom of the drill hole, or where present by the top of excessively silty intervals commonly found near the bottom of the deposit.

 

 

After reviewing the continuity and variability of the deposit, suitable resources classification criteria were developed and applied.

 

 

John T. Boyd then reviewed the proposed mining regions identified by management. Estimation of the of the in-place frac sand resources for the Kermit sand mine assumes mining operations using standard surface excavation equipment, which is widely utilized for mining of similar deposit types. As such, the estimates were subject to the following setbacks and slope requirements:

 

   

50 ft inside of property lines.

 

   

300 ft from pipeline easements.

 

   

50 ft around the wet and dry process plant areas, housing camp area, and main access road/right of way.

 

   

An overall pit wall slope of 3:1 (approximately 19 degrees).

 

 

In-place volumes for each of the proposed mining blocks were calculated from the geologic model within Carlson Software. A dry, in-place, bulk density of 100 pounds per cubic foot was used to calculate the in-place tonnage of frac sand.

Further information can be found in Section 6.2.1 and Section 6.2.2 of our technical report summary prepared by John T. Boyd and in the addendum to the technical report summary prepared by John T. Boyd, which are filed as Exhibits 99.1 and 99.2, respectively, to the registration statement of which this prospectus forms a part.

 

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Quality summary

Samples gathered during exploration were used to create 3 composite product samples that were tested by two separate third-party laboratories (PropTester and Stim-Lab) for API RP 19C/ISO 13503-2 proppant sand characteristics. ProFrac management also conducted in-house crush testing on samples obtained from their plant feed stream. Both of the independent laboratories showed similar results overall, with management’s internal laboratory testing on crush strength showing roughly 1,000 psi lower than each third-party laboratory. Testing was performed on various product sizes; however, for purposes of this estimate, John T. Boyd discussed only the 40/70 mesh and 70/200 mesh samples.

 

   
    

Average API/ISO Test Results By Product Size

 
     40/70 mesh      70/200 mesh  
Test    Result      Recommended
Specification
     Result  

Sphericity

     0.7       0.6        0.7  

Roundness

     0.6       0.6        0.6  

Acid Solubility (%)

     2.7      3.0        3.4  

Turbidity (NTU)

     n/a       250        n/a  

K-Value (000 psi)

     7               10  

 

 

 

*   100-mesh proppant sand material currently does not have an API/ISO specification

The composited sample testing suggests the Kermit sand mine is capable of producing frac sands which meet minimum API/ISO recommended testing characteristics.

The relatively dense drill hole coverage, combined with the frequency of sample intervals taken during exploration, provides a sufficiently detailed understanding of the extent and quality of the frac sand deposit underlying the Kermit sand mine to support the estimates of reserves reported herein.

Data verification

John T. Boyd did not verify historic drill hole data by conducting independent drilling in areas already explored. It is customary in preparing proppant sand resource and reserve estimates to accept basic drilling and quality testing data as provided by management, subject to the reported results being judged representative and reasonable.

John T. Boyd’s efforts to judge the appropriateness and reasonability of the source exploration data included reviewing provided drilling logs, sampling procedures, frac sand quality testing results, examining archival sample intervals, and discussing aspects of developing the Kermit sand mine with us during a site visit.

Market analysis

Permit submissions for horizontal oil and gas wells in the Permian Basin indicate a continuation of strong drilling ahead. The increase in demand for frac sand for use in the hydraulic fracturing process has resulted in a significant rise in sand prices as well as constraints on supply availability. According to Lium, total U.S. frac sand demand is expected to increase by 31% in 2022 compared to 2021 and reach 117 million tons, with the Permian expected to account for approximately 57% of the total U.S. demand. Frac sand pricing has surpassed pre-COVID levels, with Permian FOB mine pricing reaching as high as $60/ton in the spot market in the first quarter of 2022, according to Lium.

 

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Consequently, with increases in production and well completions, activity at frac sand mines in the region have increased. Per the Mine Safety and Health Administration (MSHA), operating hours for the second quarter of 2021 for Permian Basin frac sand mines were up 20% sequentially. In fact, only two mines saw a material decrease in operating hours from Q1 2021 to Q2 2021 while several had increases of more than 80% sequentially. John T. Boyd anticipates stable frac sand pricing with a slight upside bias due to potential supply chain disruptions and high commodity input costs.

For more information, please see “Summary—Industry Trends” and Section 1.7.1 of our technical report summary prepared by John T. Boyd which is filed as Exhibit 99.1 to the registration statement of which this prospectus forms a part.

Surface and mineral rights

A portion of our Kermit sand mine reserves in Winkler County, Texas are located on approximately 630 acres that we lease under a lease that terminates in 2052. The lease imposes a royalty rate of 2% of gross sales revenue and requires that we commence production from the leased premises by January 1, 2032.

Our resources

There are no reportable frac sand resources excluding those converted to frac sand reserves for the Kermit sand mine. Quantities of frac sand controlled by Alpine within the defined boundaries of the Kermit Property which are not reported as frac sand reserves are not considered to have potential economic viability; as such, they are not reportable as frac sand resources.

The Kermit sand mine is in an area of west Texas where the High Plains and Trans-Pecos desert regions converge. Surficial features of the High Plains region typically consist of thin clay and soil intervals covering caliche, with mesquite, juniper, and scrub grass cover. The Trans-Pecos region has numerous landform types ranging from the rising slopes of the Guadalupe Mountain Range, to the desert dune deposits of the Sand Hills areas. Just to the east of the study area, the Caprock Escarpment, a towering landform consisting of caliche capstone, abruptly stands hundreds of feet above the desert floor.

Surficial geologic units overlying the area are predominantly Quaternary age unconsolidated deposits, ranging from windblown sheet sands and dunes to alluvial sands, silts, clays, and caliche. Origins of these deposits are believed to be a combination of eroded bedrock material from the southern Rocky Mountains, and locally eroded Ogallala Formation sandstone. As portions of the southern Rockies were eroded via weathering, particles were carried to the Pecos River. Ancient flooding events of the Pecos River resulted in the suspended particles being deposited into flood plains. Once flood waters receded, winds took over, drying and further transporting these particles into the western Texas region.

The Caprock Escarpment marks the eastern-most extent of the surficial sand deposits. Winds transporting particles into the area are thought to have collided with the escarpment, slowing and dropping particles out to where they accumulated over time. Winnowing processes caused some degree of particle sorting to occur. Due to the mechanisms and long distances of particle transport, sand grains were abraded and rounded as they reached their current locations.

The Kermit sand mine contains no discernable overburden materials with the exception of sparse areas of vegetation and roots, which are easily removed during processing. The surface sheet and dune sands here are generally mineable from the surface down to the total defined depths of the deposit. As the target formation is located at the surface, there are no geologic features which would materially impact mineability of the surface sands.

 

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Quaternary unconsolidated deposition covers nearly all of the subject property, with the surficial deposits noted as generally ranging from 60-ft to over 300-ft in thickness. A generalized stratigraphic chart of the geologic units in Winkler County, Texas is presented below.

 

     
System    Series    Geologic Unit

Quaternary

  

Pleistocene / Holocene

  

Sheet and Dune Sand

   Loess
   Pleistocene    Unconsolidated Alluvium

Neogene

   Pliocene    Ogallala Formation

Our customers

Our customers consist primarily of E&P companies in the continental United States. Our top five customers accounted for approximately 44.9% and 51.8% of our revenue for the years ended December 31, 2021 and 2020, respectively. During the year ended December 31, 2021, Rockcliff Energy Management, LLC accounted for 15.4%, Sabine Oil & Gas Corporation accounted for 11.1%, Surge Energy America accounted for 7.4%, Henry Resources LLC accounted for 6.1% and EAP accounted for 4.9%, respectively, of our total revenue.

On a pro forma basis, the top ten largest customers contributed to just over 50.1% of total pro forma combined revenue.

Competition

The markets in which we operate are highly competitive. To be successful, an energy services company must provide services that meet the specific needs of E&P companies at competitive prices. Competitive factors impacting sales of our services are price, environmental profile of our equipment and operations, reputation and technical expertise, service and equipment quality, and health and safety standards. Although we believe our customers consider all of these factors, we believe price and equipment capabilities are the key factors in our customers’ criteria in choosing a service provider. While we seek to price our services competitively, we believe many of our customers elect to work with us based on our the capabilities and environmental profile of our fleet, as well as our extensive experience and operational expertise in U.S. unconventional oil and gas production, integrated business model and uniform fleet of standardized, high specification equipment.

We provide our services primarily in the West Texas, East Texas/Louisiana, South Texas, Oklahoma, Uinta and Appalachian regions, and we compete against different companies in each of those locations. Our major competitors include Halliburton Company, Liberty Oilfield Services Inc. and NexTier Oilfield Solutions Inc.

Seasonality

Our results of operations have historically reflected seasonal tendencies, generally in the fourth quarter, relating to the conclusion of our customers’ annual capital expenditure budgets, the holidays and inclement winter weather during which we may experience declines in our operating results.

Operating risks and insurance

Our operations are subject to hazards inherent in the energy services industry, such as accidents, blowouts, explosions, fires and spills and releases that can cause personal injury or loss of life, damage or destruction of property, equipment, natural resources and the environment and suspension of operations.

In addition, claims for loss of oil and natural gas production and damage to formations can occur in the oilfield services industry. If a serious accident were to occur at a location where our equipment and services are being used, it could result in our being named as a defendant in lawsuits asserting large claims.

 

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Because our business involves the transportation of heavy equipment and materials, we may also experience traffic accidents which may result in spills, property damage and personal injury.

Despite what we view as our strong safety record and our efforts to maintain safety standards, we from time to time have suffered accidents in the past and anticipate that we could experience accidents in the future. In addition to the property damage, personal injury and other losses from these accidents, the frequency and severity of these incidents affect our operating costs and insurability and our relationships with customers, employees, regulatory agencies and other parties. Any significant increase in the frequency or severity of these incidents, or the general level of compensation awards, could adversely affect the cost of, or our ability to obtain, workers’ compensation and other forms of insurance, and could have other material adverse effects on our financial condition and results of operations.

We maintain commercial general liability, workers’ compensation, business auto, commercial property, excess liability, and directors and officers insurance policies providing coverages of risks and amounts that we believe to be customary in our industry. Further, we have pollution legal liability coverage for our business entities, which would cover, among other things, third party liability and costs of clean-up relating to environmental contamination on our premises, while our equipment is in transit and while on our customers’ job site. With respect to our hydraulic fracturing operations, coverage would be available under our pollution legal liability policy for any surface environmental clean-up and liability to third parties arising from any surface contamination. We also have certain specific coverages for some of our business segments, including for our hydraulic fracturing services.

Although we maintain insurance coverage of types and amounts that we believe to be customary in the industry, we are not fully insured against all risks, either because insurance is not available or because of the high premium costs relative to perceived risk. Further, insurance rates have in the past been subject to wide fluctuation and changes in coverage could result in less coverage, increases in cost or higher deductibles and retentions. Liabilities for which we are not insured, or which exceed the policy limits of our applicable insurance, could have a material adverse effect on us. See “Risk Factors” for a description of certain risks associated with our insurance policies.

Environmental and occupational health and safety regulations

Environmental, health and safety matters and regulation

Our operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection, and occupational health and safety. Numerous federal, state and local governmental agencies issue regulations that often require difficult and costly compliance measures that could carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may, for example, restrict the types, quantities and concentrations of various substances that can be released into the environment, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically or seismically sensitive areas and other protected areas, or require action to prevent or remediate pollution from current or former operations. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental, health and safety laws and regulations occur frequently, and any changes that result in more stringent and costly requirements could materially adversely affect our operations and financial position. For example, following the election of President Biden and Democratic control in both houses of Congress, it is possible that our operations may be subject to greater environmental, health and safety restrictions, particularly with regards to hydraulic fracturing, permitting and GHG emissions. We have not experienced any material adverse effect from compliance with current requirements; however, we cannot guarantee this will always be the case.

Below is an overview of some of the more significant environmental, health and safety requirements with which we must comply. Our customers’ operations are subject to similar laws and regulations. Any material adverse effect of these laws and regulations on our customers’ operations and financial position may also have an indirect material adverse effect on our operations and financial position.

 

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Waste Handling.    We handle, transport, store and dispose of wastes that are subject to the Resource Conservation and Recovery Act (“RCRA”) and comparable state laws and regulations, which affect our activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although certain petroleum production wastes are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent requirements of non-hazardous waste provisions.

Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. Moreover, the EPA or state or local governments may adopt more stringent requirements for the handling of non-hazardous wastes or re-categorize some non-hazardous wastes as hazardous wastes in the future. Indeed, legislation has been proposed from time to time in U.S. Congress to re-categorize certain oil and natural gas exploration, development and production wastes as hazardous wastes. Several environmental organizations have also at times petitioned the EPA to modify existing regulations to re-categorize certain oil and natural gas exploration, development and production wastes as hazardous. Any such changes in these laws and regulations could have a material adverse effect on our capital expenditures and operating expenses. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of oil and natural gas E&P wastes could increase our costs to manage and dispose of such wastes.

Remediation of Hazardous Substances.    The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA” or “Superfund”) and analogous state laws generally impose liability without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Liability for the costs of removing or remediating previously disposed wastes or contamination, damages to natural resources, the costs of conducting certain health studies, amongst other things, is strict and joint and several. In the course of our operations, we use materials that, if released, would be subject to regulation under CERCLA and comparable state laws. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such hazardous substances have been released. Such liability could require us to make significant expenditures to investigate and remediate such contamination or attain and maintain compliance with such laws, and may otherwise have a material adverse effect on our results of operations, competitive position or financial condition.

NORM.    In the course of our operations, some of our equipment may be exposed to naturally occurring radioactive materials (“NORM”) associated with oil and gas deposits and, accordingly, may result in the generation of wastes and other materials containing NORM. NORM exhibiting levels of radiation in excess of established state standards are subject to special handling and disposal requirements, and any storage vessels, piping and work area affected by NORM may be subject to remediation or restoration requirements.

Water Discharges.    The Clean Water Act (“CWA”), SDWA, Oil Pollution Act (“OPA”) and analogous state laws and regulations impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other oil and gas wastes, into regulated waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The discharge of dredge and fill material into regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers (the “Corps”). The scope of these regulated waters has been subject to controversy in recent years. In September 2015, the EPA and the Corps issued new rules revising the definition of “waters of the United States” (the “Clean Water Rule”), but in April 2020, the EPA and the Corps replaced the Clean Water Rule with the Navigable Waters Protection Rule, which narrows the definition of “waters of the United States” to four categories of jurisdictional waters and includes twelve categories of exclusions, including groundwater. However, these rulemakings are currently subject to litigation. In August 2021, a federal judge in the District of Arizona struck down the Navigable Waters Protection Rule, and the Biden administration and the Corps have announced that they have stopped enforcing the Navigable Waters Protection Rule nationwide, and that they are reverting back to the 1986 definition of “waters of the United

 

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States.” In December 2021, the EPA and Corps published the first of two proposed rulemakings, including a definition largely in keeping with a broader pre-2015 definition and related regulatory guidance and case law. A second proposed rulemaking expanding on this definition is expected later in 2022. In January 2022, the Supreme Court agreed to hear a case regarding the jurisdictional reach of “water of the United States.” To the extent any new rules or court decisions expand the scope of the CWA’s jurisdiction, ProFrac’s customers could face increased costs and delays with respect to obtaining permits, including for dredge and fill activities in wetland areas.

Noncompliance with the CWA, SDWA, OPA, or other laws or regulations relating to water discharges may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations, for us or our customers. The process for obtaining permits also has the potential to delay operations. Additionally, spill prevention, control and countermeasure plan requirements require appropriate containment berms and similar structures to help prevent the contamination of regulated waters.

Air Emissions.    The CAA and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other emissions control requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants from specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, EPA has established emission control requirements for crude oil and natural gas production and processing operations and established criteria for aggregating multiple small surface sites into a single source for air quality permitting purposes, which could cause small facilities, on an aggregate basis, to be deemed a major source subject to more stringent air permitting processes and requirements. These and other laws and regulations may increase the costs of compliance for some facilities where we operate. Obtaining or renewing permits also has the potential to delay the development of oil and natural gas projects.

Climate Change.    Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of carbon dioxide, methane and other GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources.

In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, President Biden has highlighted addressing climate change as a priority of his administration and has issued several executive orders addressing climate change. Moreover, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, and together with the DOT, set GHG emissions and fuel economy standards for vehicles in the United States. The regulation of methane from oil and gas facilities has been subject to uncertainty in recent years. The EPA previously had promulgated NSPS imposing limitations on methane emissions from sources in the oil and gas sector. Subsequently, in September 2020, the Trump Administration rescinded those methane standards and removed the transmission and storage segments from the oil and gas source category under the CAA’s NSPS. However, in June 2021, President Biden signed a resolution passed by the U.S. Congress under the Congressional Review Act nullifying the September 2020 rule, effectively reinstating the prior standards. In November 2021, as required by President Biden’s executive order, the EPA proposed new regulations to expand NSPS requirements for oil and gas sector sources and establish comprehensive standards of performance and emission guidelines for methane and volatile organic compound emissions from existing operations in the oil and gas sector, including the exploration and production, transmission, processing, and storage segments. The EPA has announced that the agency hopes to finalize these rulemakings by the end of 2022. Once finalized, the regulations are likely to be subject to legal challenge and will also need to be incorporated into the states’ implementation plans, which will need to be approved by the EPA in individual rulemakings that could also be subject to legal challenge. The reinstatement of direct regulation of methane emission for new sources and the promulgation of requirements for existing oil and gas customers could result in increased costs for our customers and consequently adversely affect demand for our services.

 

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Separately, various states and groups of states have adopted or are considering adopting legislation, regulation or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. For example, several states, including Pennsylvania and New Mexico, have proposed or adopted regulations restricting the emission of methane from E&P activities. At the international level, the United Nations-sponsored “Paris Agreement” requires member states to submit non-binding, individually-determined reduction goals known as Nationally Determined Contributions every five years after 2020. President Biden has recommitted the United States to the Paris Agreement and, in April 2021, announced a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. In November 2021, President Biden released “The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050,” which, among other things, explains that the U.S. and EU are co-leading the “Global Methane Pledge” that aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels. The impacts of these orders, pledges, agreements, and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, cannot be predicted at this time.

Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate change related pledges made by certain candidates now in public office. On January 27, 2021, President Biden issued an executive order that calls for substantial action on climate change, including, among other things, the increased use of zero-emission vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risks across government agencies and economic sectors. The Biden Administration has previously also issued orders suspending the issuance of new leases pending a study, for oil and gas development on federal lands. For more information, see our regulatory disclosure titled “Regulation of Hydraulic Fracturing and Related Activities.” As a result, we cannot predict the full impact of these developments or whether the Biden Administration may pursue further restrictions. Other actions that could be pursued by the Biden Administration may include the imposition of more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities, as well as more restrictive GHG emission limitations for oil and gas facilities.

Additionally, the Securities and Exchange Commission recently proposed new rules relating to the disclosure of a range of climate-related risks. We are currently assessing this rule but at this time we cannot predict the costs of implementation or any potential adverse impacts resulting from the rule. To the extent this rule is finalized as proposed, we or our customers could incur increased costs related to the assessment and disclosure of climate-related risks. In addition, enhanced climate disclosure requirements could accelerate the trend of certain stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon intensive sectors.

The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate the GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for oil and natural gas, which could reduce demand for our services. Additionally, political, litigation and financial risks may result in our customers restricting or cancelling production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing their ability to continue to operate in an economic manner, which also could reduce the demand for our services. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.

Endangered and Threatened Species.    Environmental laws such as the ESA and analogous state laws may impact exploration, development and production activities in areas where we operate. The ESA provides broad protection for species of fish, wildlife and plants that are listed as threatened or endangered. Similar protections are offered to migratory birds under the MBTA and various state analogs. FWS may identify previously unidentified endangered or threatened species or may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. For example, the dunes sagebrush lizard, which is found only in the active and semi-stable shinnery oak dunes of southeastern New Mexico and adjacent portions of Texas (including areas where our customers operate), was a candidate species for listing under the ESA by the FWS for many years. As a result of a recent settlement with the environmental groups, the FWS, in July 2020, acted on a petition to list the dunes sagebrush lizard

 

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finding sufficient information to warrant a formal one-year review to consider listing the species. While the listing review is ongoing, FWS has also developed a conservation agreement that would implement certain protective practices for the species and authorize incidental take of the species resulting from certain covered activities, including exploration and development of oil and gas fields. The conservation agreement is known as a CCAA. We have joined the CCAA in an effort to mitigate potential impacts on our business of a listing of the dunes sagebrush lizard by the FWS.

On June 1, 2021, FWS also proposed to list two distinct population segments of the lesser prairie-chicken under the ESA, in response to a 2016 petition from conservation groups. Separately, on July 1, 2021, a lawsuit was filed by conservation groups to overturn a 2019 FWS decision that listing the eastern hellbender salamander under the ESA was not warranted. In October 2021, the Biden administration published two rules that reversed changes made by the Trump administration, namely to the definition of “habitat” and a policy that made it easier to exclude territory from critical habitat. On March 23, 2022, the FWS proposed a rule to redesignate the northern long-eared bat from a threatened species to an endangered species under ESA, and to remove its species-specific rule that excluded most development activities from the ESA’s prohibition on taking listed species. To the extent any protections are implemented for these or any other species or habitat, it could cause us or our customers to incur additional costs or become subject to operating restrictions or operating bans in the affected areas.

Regulation of Hydraulic Fracturing and Related Activities.    Our hydraulic fracturing operations are a significant component of our business. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has previously issued a series of rules under the CAA that establish new emission control requirements for certain oil and natural gas production and natural gas processing operations and associated equipment. BLM also finalized rules to impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. While this regulation was subsequently rescinded in December 2017, which rescission was upheld by the District Court of Northern California, litigation is ongoing. Additionally, the Biden Administration may seek to revisit these regulations. Separately, the Biden Administration may also pursue further restriction of hydraulic fracturing and other oil and gas development on federal lands. For example, on January 27, 2021, President Biden issued an executive order that, among other things, called for the elimination of fossil fuel subsidies from federal budget requests beginning in 2022 and suspended the issuance of new leases for oil and gas development on federal lands to the extent permitted by law and called for a review of existing leasing and permitting practices for such activities on federal lands (the order clarifies that it does not restrict such operations on tribal lands that the federal government merely holds in trust).

In response to President Biden’s executive order, the Department of Interior issued a report recommending various changes to the federal leasing program, though many such changes would require Congressional action. However, legal challenges to this suspension are ongoing, and the District Court for the Western District of Louisiana has issued a preliminary injunction against the implementation of this suspension while such challenges are pending. The Biden Administration has appealed the injunction, but is complying with the injunction during the appeals process. Separately, the state of Louisiana, among other states, have challenged the Biden Administration’s use of the social cost of carbon in its decision-making, including federal leasing decisions, resulting in an injunction from the Western District of Louisiana preventing the Biden Administration’s use of the social cost of carbon. In response, the Biden Administration again halted leasing activities. However, the Fifth Circuit Court of Appeals has overturned the lower court’s decision, and the plaintiff states have announced that they plan to seek review by the Supreme Court. On April 15, 2022, the Department of the Interior announced that it would again resume leasing on federal lands, though with significant changes to the program, including an 80% reduction in the number of acres nominated and the first-ever increase in onshore royalties, to 18.7% from 12.5%. Separately, there has been a significant reduction in the number of approvals of applications for permits to drill on federal lands in 2022. As a result of the foregoing, there is significant uncertainty and increased regulatory risks and costs relating to onshore oil and

 

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gas exploration and production activities. These issues could result in decreased activity on federal land, adversely impacting demand for our services.

As a result, we cannot predict the final scope of regulations or restrictions that may apply to oil and gas operations on federal lands, nor the outcome of pending litigation. Although the executive order does not apply to existing operations under valid leases, ProFrac cannot guarantee that further action will not be taken to curtail oil and gas development on federal lands. Any restrictions for new or existing production activities on federal land could adversely impact our customer’s operations and consequently reduce demand for our services. The increase in royalties associated with leasing on federal lands, and any future increases that may occur, may adversely impact exploration and production activities on federal lands and reduce demand for our services. Further, legislation to amend the SDWA to repeal the exemption for hydraulic fracturing (except when diesel fuels are used) from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, have previously been proposed in Congress. Several states and local jurisdictions in which we or our customers operate also have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids.

Federal and state governments have also investigated whether the disposal of produced water into underground injection wells has caused increased seismic activity in certain areas. In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma has issued rules for wastewater disposal wells that impose permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults and also, from time to time, has implemented plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. In particular, the Oklahoma Corporation Commission’s well completion seismicity guidelines for operators in the SCOOP and STACK require hydraulic fracturing operations to be suspended following earthquakes of certain magnitudes in the vicinity. In addition, the Oklahoma Corporation Commission’s Oil and Gas Conservation Division has previously issued an order limiting future increases in the volume of oil and natural gas wastewater injected into the ground in an effort to reduce the number of earthquakes in the state. The Texas Railroad Commission has adopted similar rules.

If new laws or regulations that significantly restrict hydraulic fracturing and related activities are adopted, such laws could make it more difficult or costly to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing is further regulated at the federal or state level, fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply could have a material adverse effect on our financial condition and results of operations.

OSHA Matters.    The Occupational Safety and Health Act (“OSHA”) and comparable state statutes 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. In March 2016, the U.S. Occupational Safety and Health Administration issued a final rule to impose stricter standards for worker exposure to silica; our sand mining operations are subject to this rule and, moreover, the rule went into effect on June 23, 2021 for hydraulic fracturing activities. As a result, we or our customers may be required to incur additional costs associated with compliance with these standards, which costs may be material.

Mining Activities.    Our sand mining operations are subject to the oversight of the U.S. Mine Safety and Health Administration (“MSHA”), which is the primary regulatory agency with jurisdiction over the commercial silica industry. MSHA regulates quarries, surface mines, underground mines, and the industrial mineral processing facilities associated with quarries and mines. MSHA administers and enforces the provisions of the Federal Mine Safety and

 

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Health Act of 1977 (“FMSHA”), as amended by the Mine Improvement and New Emergency Response Act of 2006. FMSHA imposes stringent health and safety standards on numerous aspects of our operations inclusive of mineral extraction and processing operations, transportation and transloading of silica and delivery of silica sand to well sites. These standards include, among others, the training of personnel, operating procedures, operating and safety equipment, and other matters. As part of MSHA’s oversight, its representatives must perform at least two unannounced inspections annually for each surface mining facility in its jurisdiction.

Human capital

Our employees are a critical asset which are key to our innovative culture and overall success. We are focused on our high-performance culture through attracting, engaging, developing, retaining and rewarding top talent. We strive to enhance the economic and social well-being of our employees and the communities in which we operate. We are committed to providing a welcoming, inclusive environment for our workforce, with best-in-class training and career development opportunities to enable employees to thrive and achieve their career goals.

As of March 24, 2022, we employed 2,522 people, none of whom are represented by labor unions or subject to collective bargaining agreements.

Health and Safety.    The health, safety, and well-being of our employees is of the utmost importance. We are an industry leader with a proven track record in safety with a TRIR of .42 for the year ended December 31, 2021, including our manufacturing division, compared to the industry average of .70.

We provide employees the option to participate in health and welfare plans, including medical, dental, life, accidental death and dismemberment and short-term and long-term disability insurance plans. We also offer a number of health and wellness programs, including telemedicine, health screens and fitness reimbursement as well as access to the Employee Assistance Program which provides employees and their family members access to professional providers to help navigate challenging life events 24 hours a day/365 days a year.

In response to COVID-19, we adopted enhanced safety measures and practices to protect employee health and safety and continue to follow guidelines from the Centers for Disease Control to protect our employees and minimize the risk of business disruption.

Legal proceedings

ProFrac Services, LLC entered into a Master Purchase Agreement For Products And/Or Services with Lonestar Prospects, Ltd. d/b/a Vista Sand (“Vista”), dated November 27, 2017 (the “Vista MSA”), as amended by the First Addendum to Vista MSA and the First Amendment to Vista MSA, both of which are dated June 10, 2018 (collectively, the “Agreement”). Under the terms of the Vista MSA, Services agreed to purchase certain quantities of sand from Vista. Vista filed a complaint against Services in the United States Bankruptcy Court for the Northern District of Texas on March 15, 2021, in which it alleges that Services breached the terms of the Agreement by failing to purchase the required amount of sand or pay for the underpurchased amounts as required by the Agreement. Vista is seeking damages of approximately $8.31 million. Vista and Services have entered into a mutually agreed upon Scheduling Order signed by the Court on February 12, 2022. Trial docket call for this matter is currently scheduled for September 6, 2022.

From time to time we may be involved in litigation relating to claims arising out of our operations in the normal course of business, including workers’ compensation claims and employment related disputes. Other than as described above, we are not currently a party to any legal proceedings that, if determined adversely against us, either individually or in the aggregate, would have a material adverse effect on our business, results of operations, cash flows or financial condition and are not aware of any material legal proceedings contemplated by governmental authorities. We are however, named defendants in certain lawsuits, investigations and claims arising in the ordinary course of conducting our business and we may be named defendants in similar lawsuits, investigations and claims in the future. While the outcome of these lawsuits, investigations and claims cannot be predicted with certainty, we do not expect these matters, if decided adversely, to have a material adverse effect on our business, results of operations, cash flows or financial condition.

 

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Management

The following table sets forth the names, ages and titles of our directors and executive officers.

 

     
Name    Age        Position
Ladd Wilks      36        Chief Executive Officer

Lance Turner

     42        Chief Financial Officer

Coy Randle

     60        Chief Operating Officer

Robert Willette

     46        Chief Legal Officer, Secretary

Matthew D. Wilks

     39        Executive Chairman of the Board

Sergei Krylov

     44        Director Nominee

Terry Glebocki

     59        Director Nominee

Stacy Nieuwoudt

     42        Director Nominee

Gerald Haddock

     74        Director Nominee

 

Ladd Wilks

Ladd Wilks has served as our Chief Executive Officer since May 2016. Since February 2012, Mr. Wilks has also served as Vice President of Breckenridge Geophysical, Inc. Mr. Wilks owns a controlling interest in two private E&P companies. Mr. Wilks currently sits on the Board of Directors of Cisco Safe, the Cisco Recreation Foundation and 13 Foundation. From March 2008 to July 2011, Mr. Wilks served as VP of Logistics of FTSI. Additionally, Mr. Wilks is an executive officer at Wilks Brothers and has an extensive background with our Company arising from his familial connection to our founders as the son of Farris Wilks and nephew of Dan Wilks.

Lance Turner

Lance Turner has served as our Chief Financial Officer since March 2022. From October 2015 to March 2022, Mr. Turner served as Chief Financial Officer and Treasurer of FTSI. Mr. Turner joined FTSI in April 2014 as Director of Finance and was promoted to Vice President of Finance of FTSI in January 2015. Prior to that, Mr. Turner spent approximately 11 years with Ernst & Young LLP, with the majority of that time in its transactions services group coordinating and advising clients on buy side and sell side transactions in various industries. He earned a Bachelor of Business Administration and a Master of Professional Accounting from the University of Texas at Austin and is a Certified Public Accountant in the state of Texas.

Coy Randle

Coy Randle joined ProFrac in May 2018 and has served as our Chief Operating Officer since October 2018. Mr. Randle has over 39 years’ experience in the energy industry. Prior to joining the company, Mr. Randle provided technical consulting services for Nolan Transportation Group. Mr. Randle served as President and Chief Operating Officer of FTSI from March 2010 to October 2015 and as Senior Vice President of Operations from January 2008 to March 2010.

 

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Robert Willette

Robert Willette has served as our Chief Legal Officer and Secretary since November 2021. Since October 2020, Mr. Willette has served as Assistant General Counsel of Wilks Brothers. From August 2017 to October 2020, Mr. Willette served as Senior Vice President, General Counsel, Corporate Secretary, Chief Compliance and ESG Officer of Carbo Ceramics Inc. Prior to that, Mr. Willette served as General Counsel and Corporate Secretary for Texon L.P., which transports and markets crude oil, natural gas and natural gas liquids. Mr. Willette holds a B.S., an M.B.A., and a J.D. from the University of Kansas.

Matthew D. Wilks

Matthew D. Wilks has served as Executive Chairman of our board of directors since August 2021 and has served as our President since October 2018. Previously, Mr. Wilks served as our Chief Financial Officer from May 2017 to August 2021. Mr. Wilks also has served as Vice President of Investments for Wilks Brothers since January 2012. From 2010 to 2012, Mr. Wilks served as Vice President of Logistics for FTSI. Additionally, Mr. Wilks served as a member of the board of directors of Approach Resources, Inc., an E&P company focused on the exploration, development and production of unconventional oil and gas resources in the United States. Mr. Wilks’ background in numerous roles specific to our Company and his familial connection to our founders as the son of Dan Wilks and nephew of Farris Wilks, allow him to engage in board deliberations with valuable insight and experience.

Sergei Krylov

Sergei Krylov has been nominated to serve on our board of directors commencing concurrently with the consummation of this offering. Mr. Krylov has been in the energy industry for more than 20 years, both as an investment banker and as an executive officer. Currently, Mr. Krylov serves as Investment Partner and Chief Financial Officer of Wilks Brothers, LLC. From 2014 to 2020, Mr. Krylov served as an executive at Approach Resources Inc., a NASDAQ listed exploration and production company focused on Permian basin, initially as Executive Vice President and Chief Financial O