ProFrac Holding (ACDC) 424B3Prospectus supplement

Filed pursuant to Rule 424(b)(3)

Registration No. 333-266465

PROSPECTUS SUPPLEMENT NO. 13

(to Prospectus dated August 8, 2022)

ProFrac Holding Corp.

Up to 1,545,575 shares of Class A common stock

This prospectus supplement supplements the prospectus dated August 8, 2022 (the “Prospectus”), which forms a part of our registration statement on Form S-1 (No. 333-266465). This prospectus supplement is being filed to update and supplement the information in the Prospectus with the information contained in our Annual Report on Form 10-K filed with the Securities and Exchange Commission on March 15, 2024 (the “Annual Report”). Accordingly, we have attached the Annual Report to this prospectus supplement.

The Prospectus and this prospectus supplement relate to the resale by the selling stockholders identified in the Prospectus (the “Selling Stockholders”), or their permitted transferees, of up to 1,545,575 shares of Class A common stock of ProFrac Holding Corp., a Delaware corporation. We will not receive any of the proceeds from such sales of the shares of our Class A common stock by the Selling Stockholders.

This prospectus supplement updates and supplements the information in the Prospectus and is not complete without, and may not be delivered or utilized except in combination with, the Prospectus, including any amendments or supplements thereto. This prospectus supplement should be read in conjunction with the Prospectus and if there is any inconsistency between the information in the Prospectus and this prospectus supplement, you should rely on the information in this prospectus supplement.

Our Class A common stock is listed on the Nasdaq Global Select Market under the symbol “ACDC.” The last reported sales price of our Class A common stock on the Nasdaq Global Select Market on March 11, 2024 was $7.82 per share.

Investing in our Class A common stock involves risks. See “Risk Factors” beginning on page 36 of the Prospectus and “Risk Factors” beginning on page 17 of the accompanying Annual Report on Form 10-K, 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 supplement or the Prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The date of this prospectus supplement is March 19, 2024.

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

(Mark One)

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

For the fiscal year ended: December 31, 2023

or

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

For the transition period from __________ to __________

Commission file number: 001-41388

333 Shops Boulevard, Suite 301, Willow Park, Texas 76087

(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code: (254) 776-3722

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

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

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

Yes ☐ No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes ☐ No ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

Yes ☒ No ☐

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

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

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

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

The aggregate market value of the registrant’s Class A common stock, $0.01 par value per share, held by non-affiliates of the registrant as of June 30, 2023, the last business day of the registrant’s most recently completed second fiscal quarter, was $268,273,733 based on the closing price of $11.16 per share of the Class A common stock, as reported on The Nasdaq Global Select Market on that date.

As of March 11, 2024, the registrant had 159,594,192 shares of Class A common stock, $0.01 par value per share, outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement for the 2024 Annual Meeting of Stockholders, which will be filed with the U.S. Securities and Exchange Commission within 120 days after December 31, 2023, are incorporated by reference into Part III of this Annual Report on Form 10-K.

TABLE OF CONTENTS

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K (this “Annual Report”) contains certain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Forward-looking statements include those that express a belief, expectation or intention, as well as those that are not statements of historical fact. Forward-looking statements include information regarding our future plans and goals, as well as our expectations with respect to:

These forward-looking statements may be accompanied by words such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “outlook,” “plan,” “potential,” “predict,” “project,” “will,” “should,” “could,” “would,” “likely,” “future,” “budget,” “pursue,” “target,” “seek,” “objective,” or similar expressions that are predictions of or indicate future events or trends that do not relate to historical matters.

The forward-looking statements in this Annual Report speak only as of the date of this Annual Report, or such other date as specified herein. We disclaim any obligation to update these statements unless required by law, and we caution you not to place undue reliance on them. Forward-looking statements are not assurances of future performance and involve risks and uncertainties. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties include, but are not limited to, the following:

These and other important factors that could affect our operating results and performance are described in (i) Part I, Item 1A “Risk Factors” and in Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report, and elsewhere within this Annual Report, (ii) our other reports and filings we make with the SEC from time to time, and (iii) other announcements we may make from time to time. Should one or more of the risks or uncertainties described in the documents above or in this Annual Report occur, or should underlying assumptions prove incorrect, our actual results, performance, achievements or plans could differ materially from those expressed or implied in any forward-looking statements. All such forward-looking statements in this Annual Report are expressly qualified in their entirety by the cautionary statements in this section.

Summary of Principal Risk Factors

Our business is subject to a number of risks and uncertainties. The following is a summary of the principal risk factors that could materially adversely affect our business, financial condition and results of operations. A more complete statement of those risks and uncertainties is set forth in “Risk Factors” in Item 1A of Part I of this Annual Report.

PART I

ITEM 1. BUSINESS

Unless the context otherwise requires or as is otherwise indicated, references in this Annual Report to the “Company,” “ProFrac,” “we,” “our” and “us,” or like terms, refer to (i) before the completion of the Corporate Reorganization, ProFrac Holdings, LLC, a Texas limited liability company (“ProFrac LLC”), and its consolidated subsidiaries; and (ii) following the completion of the Corporate Reorganization, ProFrac Holding Corp., a Delaware corporation (the “Issuer”), and its consolidated subsidiaries.

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 well stimulation services, including back-up pumping capacity.

Overview and Strategy

ProFrac Holding Corp. is a technology-focused, vertically integrated, innovation-driven energy services holding company providing hydraulic fracturing, proppant production, other completion services and other complementary products and services to leading upstream oil and natural gas companies engaged in the exploration and production ("E&P") of North American unconventional oil and natural gas resources throughout the United States. Founded in 2016, ProFrac was built to be the go-to service provider for E&P companies' most demanding hydraulic fracturing needs. ProFrac is focused on employing new technologies to significantly reduce "greenhouse gas" emissions and increase efficiency in what has historically been an emissions-intensive component of the unconventional E&P development process. ProFrac Corp. operates in three business segments: stimulation services, proppant production and manufacturing.

We employ a differentiated business model, focused on vertical integration, technological innovation and actively acquiring assets and businesses that expand our capabilities. In combination with our deep technical expertise, our ability to design and manufacture equipment and produce proppant positions us to custom tailor our products and services to meet the needs of our customers. Additionally, we believe we are uniquely positioned as an industry consolidator. We have a focused M&A strategy to acquire high-quality businesses at attractive valuations that increase our scale and expand our technological and supply chain competencies. Since the completion of our initial public offering (“IPO”) in 2022, we have completed six acquisitions adding approximately 18.7 million tons of annual sand capacity and 13 frac fleets. These acquisitions provide us with an opportunity to generate attractive returns, when combined with our operational and commercial platform.

We believe the technical and operational capabilities of our fleets, our frac sand production and equipment manufacturing capabilities uniquely position us to capitalize on the demand for well stimulation services to support the ongoing development of American oil and gas reserves.

Our operations are focused on the most active unconventional regions in the United States, where we have cultivated deep and longstanding customer relationships with some of those regions’ leading E&P companies. We believe we are among the largest well stimulation services providers in the United States, with 30 active fleets as of January 31, 2024. We operate throughout nearly all major unconventional oil and gas basins in the United States and our scale and geographical footprint provide us with both operating leverage as well as exposure to a diversified customer and commodity mix.

We are also the largest producer of in-basin frac sand in the United States, with approximately 21.5 million tons of annual nameplate capacity across eight frac sand mines in the Haynesville Shale in East Texas, Louisiana and Arkansas (the “Haynesville”), the Permian Basin in West Texas and New Mexico (the “Permian”) and the Eagle Ford Shale in South Texas (the “Eagle Ford”). In addition to the significant quantitative and qualitative benefits that our Proppant Production segment provides to our Stimulation Services Segment, our scale, reach and proximity of our mines to customers’ well sites enable reliable, low-cost sand production for third party proppant customers.

Our business combines a young fleet of modern, technologically advanced pressure pumping equipment with vertically integrated proppant, chemicals and manufacturing, enabling us to deliver premium products and service quality while maintaining an advantaged cost structure.

Operating Segments

Stimulation Services Segment

ProFrac is one of the largest providers of well stimulation services in the United States. As of January 31, 2024, we had 30 active fleets. Of our active fleets 16 are Tier IV fleets (15 of which are dual fuel or DGB), ten are Tier II (two of which are dual fuel) and four are electric fleets. Currently, our operations are focused on the Permian, Eagle Ford, Haynesville,

Appalachia, the Bakken and the Rockies. With our broad operating footprint, we are able to serve a diversified customer base with balanced exposure to public and private E&P customers that are developing both oil and natural gas reserves.

Our conventional hydraulic fracturing fleets have been designed to handle the most demanding well completions, which are characterized by higher pumping pressures, higher pumping volumes and longer horizontal wellbores. We continue to upgrade and overhaul our fleets with the goal of having all of our conventional fleets similarly equipped with lower-emission Tier IV diesel engines, a process made cheaper by our in-house manufacturing capabilities detailed below. This strategy aligns with our environmental focus to minimize our carbon footprint as a part of our goal to have all of our conventional fleets equipped with emissions reduction technology.

In addition to our conventional fleets, we are one of the largest providers of electric powered fleets in the industry. This technology utilizes electric motors powered by lower-cost, lower-emission power solutions, primarily using on-site generation from natural gas produced and conditioned in the field or compressed natural gas (“CNG”). We believe that this fuel supply can provide our customers with additional tools to meet their emissions and sustainability goals by reducing their reliance on diesel fuel, as well as offer significant fuel cost savings. These fleets are intended to provide our customers a suite of options to satisfy their ESG objectives while maximizing operating efficiency.

Our stimulation services competitors include Halliburton Company, Liberty Energy Inc. and NexTier Completion Solutions Inc.

Proppant Segment

We are the largest producer of in-basin frac sand in the United States, with approximately 21.5 million tons of annual nameplate capacity across eight frac sand mines in the Haynesville Shale in East Texas, Louisiana and Arkansas (the “Haynesville”), the Permian Basin in West Texas and New Mexico (the “Permian”) and the Eagle Ford Shale in South Texas (the “Eagle Ford”). Our primary objective is to be the most reliable, cost-effective supplier of in-basin frac sand while maximizing value to our stockholders by generating strong cash flow. We believe that our scale, our proximity to our customers’ operations in key markets and our term contracting approach differentiates us from our competitors and positions us to meet our primary objective.

Our scale enables us to be a reliable, low-cost producer for customers in the areas in which we operate. Our mines are strategically located throughout the most active crude oil and natural gas production markets: the Haynesville, Permian and Eagle Ford. Our geographic diversification, as well as diversification across oil and natural gas production, allows us the flexibility to respond to market volatility and provides confidence in our ability to manage revenues through cycles. The proximity of our mines to the areas in which our customers operate allows them to lower transportation cost, reduce transportation time, improve reliability of delivery, reduce down time, store less proppant on-site and increase operational efficiencies.

Competitors to our proppant segment include Atlas Energy Solutions Inc., Badger Mining Corporation, Black Mountain Sand, Covia Corp., Freedom Proppants, Hi-Crush Inc., High Roller Sand, Signal Peak Silica, U.S. Silica Inc., Vista Minerals and Capital Sand Company, among others.

Manufacturing Segment

We operate facilities in which we assemble new fleets, refurbish existing fleets, rebuild engines and transmissions, and manufacture many of the components used by our fleets, including pumps, fluid ends, power ends, flow iron and other consumables. These facilities perform substantially all of the maintenance, repair and servicing of our hydraulic fracturing fleets, as well as provide in-house manufacturing capacity that enables cost-advantaged growth and maintenance. Additionally, our internal manufacturing capabilities enable us to upgrade and modernize acquired fleets in a cost-efficient manner.

Vertical integration enables us to realize a lower capital investment and operating expense by capturing the margin of manufacturing and/or maintenance, 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 we believe that it helps us mitigate supply chain constraints that have disrupted competitors’ and customers’ operations in the past. Our in-house manufacturing capabilities also allow us to rapidly implement new technologies in a cost-effective manner.

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.

2023 Significant Events

Acquisition of Producers Service Holdings LLC

On January 3, 2023, we acquired 100% of the issued and outstanding membership interest of Producers Service Holdings LLC (“Producers”), a Delaware limited liability company, an employee-owned pressure pumping services provider serving Appalachia and the Mid-Continent, for approximately $35.0 million of total transaction value, of which approximately half was payable in shares of ProFrac’s Class A common stock, par value $0.01 per share (the “Class A Common Stock”), with the remainder consisting of cash and debt assumption. A portion of the cash consideration is subject to certain customary post-closing adjustments. Through this transaction, we have added three fleets, of which two are currently active, totaling 200,000 HHP as well as a 50,000 square foot manufacturing facility located near Zanesville, OH, through which we plan to expand our manufacturing footprint to support Northeast operations.

Acquisition of Performance Proppants

On February 24, 2023, we acquired 100% of the issued and outstanding membership interests in (i) Performance Proppants, LLC, a Texas limited liability company, (ii) Red River Land Holdings, LLC, a Louisiana limited liability company, (iii) Performance Royalty, LLC, a Louisiana limited liability company, (iv) Performance Proppants International, LLC, a Louisiana limited liability company, and (v) Sunny Point Aggregates, LLC, a Louisiana limited liability company (together, “Performance Proppants”) for a total purchase consideration of approximately $462.8 million, consisting of (x) $452.4 million in cash, (y) a number of shares of Class A Common Stock equal to $6.2 million, and (z) the settlement of a pre-existing receivable of $4.2 million. Performance Proppants is a frac sand provider in the Haynesville basin.

Redemption of ProFrac LLC Units

Pursuant to the Third Amended and Restated Limited Liability Company Agreement of ProFrac Holdings, LLC, a Texas limited liability company (“ProFrac LLC”) (the “LLC Agreement”) and the Second Amended and Restated Certificate of Incorporation of ProFrac, certain members of ProFrac LLC had the right (the “Redemption Right”) to cause ProFrac LLC to redeem all or a portion of each such member’s units in ProFrac LLC (the “ProFrac LLC Units”), together with the surrender of the same number of each such member’s shares of ProFrac’s Class B common stock, par value $0.01 per share (the “Class B Common Stock”), for an equivalent number of shares of Class A Common Stock or, at the election of ProFrac’s audit committee, cash as provided for in the LLC Agreement.

Pursuant to redemption notices delivered in accordance with the LLC Agreement, all of the eligible holders of ProFrac LLC Units (the “Redeeming Members”) exercised their Redemption Right with respect to all of their ProFrac LLC Units, representing an aggregate of 104,195,938 ProFrac LLC Units (collectively, the “Redeemed Units”), together with the surrender and delivery of the same number of shares of Class B Common Stock (the “Redemption”). The Redeeming Members included entities owned by or affiliated with ProFrac’s controlling stockholders, Dan Wilks and Farris Wilks, as well as Matt Wilks, ProFrac’s Executive Chairman, an entity affiliated with Ladd Wilks, ProFrac’s Chief Executive Officer, and Coy Randle, a member of the ProFrac board of directors.

On April 7, 2023, in accordance with the LLC Agreement, ProFrac delivered a written notice to ProFrac LLC and the Redeeming Members setting forth the Company’s election to exercise its right to purchase directly and acquire the Redeemed Units (together with the surrender and delivery of the same number of shares of Class B Common Stock) from the Redeeming Members.

We subsequently acquired the Redeemed Units from the Redeeming Members by issuing an aggregate of 101,133,202 shares of Class A common stock on or about April 10, 2023 and the remaining 3,062,736 shares of Class A Common Stock on or about April 13, 2023. The surrendered shares of Class B common stock were canceled, and after giving effect to the Redemption, no shares of our Class B Common Stock remain issued and outstanding.

Issuance and Sale of Newly Designated Series A Redeemable Convertible Preferred Stock

On September 29, 2023, ProFrac entered into a purchase agreement (the “Purchase Agreement”) with THRC Holdings, LP, a Texas limited partnership (“THRC Holdings”) and FARJO Holdings, LP, a Texas limited partnership (“FARJO Holdings” and, together with THRC Holdings, the “Series A Investors”), pursuant to which ProFrac agreed to issue and sell shares of its new series of preferred stock, designated as Series A Redeemable Convertible Preferred Stock, par value $0.01 per share (the “Series A Preferred Stock”), in a private placement transaction (“Private Placement”). At the closing of the Private Placement on September 29, 2023, ProFrac issued and sold to the Series A Investors 50,000 shares of the Series A Preferred Stock at a purchase price of $1,000.00 per share. The gross proceeds to the Company from the sale of the Series A Preferred Stock were $50.0 million. The shares of Series A Preferred Stock are convertible into shares of Class A Common Stock. Holders of the Series A Preferred Stock are entitled to cumulative paid-in-kind dividends at a rate per share equal to eight percent per annum. Such dividends shall compound and be payable quarterly in arrears. The foregoing description of the Series A Preferred Stock does not purport to be complete and is qualified in its entirety by reference to the Series A Certificate of Designation, a copy of which is filed as Exhibit 3.3 to this Annual Report, and is incorporated by reference herein.

Flying A Pump Services, LLC Agreement

In June 2023, ProFrac arranged to sell certain surplus equipment and inventory components and to assign certain pre-orders for equipment to Flying A Pump Services, LLC (“Flying A”), at prices which we believe to be fair market value, for a total consideration of $36.3 million. As of June 30, 2023, we received the proceeds from this sale. Subsequent to June 30, 2023, Flying A requested changes to the mix of the assets being sold to it by the Company without altering the total consideration, and the Company and Flying A agreed to add to the transaction agreement a most favored nation clause on pricing and a condition to closing that the Company’s Audit Committee approve the final mix of assets to be transferred to Flying A. We delivered $28.9 million of these components to Flying A in 2023. We expect to deliver the remaining components to Flying A in the first half of 2024.

Debt Refinancing

In December 2023, we completed the refinancing of our existing senior secured term loan and other debt with two new financings totaling $885 million, which will both mature in 2029. As a result of these transactions, we extended our significant debt maturities to 2029, and obtained the financial flexibility to take advantage of the expected increase in activity levels in 2024. For more information, see “Note 6 – Debt” in the notes to our consolidated financial statements.

Customers

Our customers consist primarily of E&P companies in the continental United States. For the years ended December 31, 2023, and December 31, 2022, no individual customer represented more than 10% of our consolidated revenues. For the year ended December 31, 2021, our top three customers individually represented 15%, 10%, and 7% of our consolidated revenues. The loss of any of our largest customers could have a material adverse effect on our results of operations.

Seasonality

Historically, our operations have been subject to seasonal factors, and our historical financial results reflect seasonal variations. For example, we have observed a slowdown or pause by our customers around the holiday season in the fourth quarter, some of which may be related to our customers’ annual capital spending budgets. Additionally, our operating results may decline during periods of inclement weather conditions.

Human Capital Management

Our employees are a critical asset and are key to our innovative culture and overall success. We are focused on building upon our high-performance culture by attracting, engaging, developing, retaining and rewarding top talent. We strive to enhance the economic and social well-being of our employees. We are committed to providing a welcoming, inclusive environment for our workforce, with training and career development opportunities to enable employees to thrive and achieve their career goals.

As of December 31, 2023, we employed 2,949 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 utmost importance to us. We are an industry leader with a proven track record in safety with a Total Reportable Incident Rate of 0.54 for the year ended December 31, 2023, including our manufacturing division, as compared to the industry average of 1.00, according to the International Association of Oil & Gas Producers (“IOGP”).

Employee Welfare and Development. 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.

Intellectual Property

USWS has been granted over 90 patents worldwide, which begin to expire in late 2032. USWS has over 200 additional patent applications pending worldwide. Many of these patents were filed in an effort to protect USWS electric fleet technology from being duplicated by competitors. We also use proprietary technology to support our preventative maintenance program and prolong equipment useful life. Although in the aggregate, our trademarks and patents are important to us, we do not regard any single trademark, patent, or group of related trademarks or patents as critical or essential to our business as a whole. For information regarding litigation involving our intellectual property portfolio, see “Note 13 – Commitments and Contingencies” in the notes to our consolidated financial statements.

Operating Risks and Insurance

Our operations are subject to hazards inherent in the energy services industry, such as accidents, breakdowns, 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.

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 coverage 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 coverage 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 retention. Liabilities for which we are not insured, or which exceed the policy limits of our applicable insurance, could have a material adverse effect on our business and financial condition.

In addition, concerns over silicosis and other potential adverse health effects, as well as concerns regarding potential liability from the use of silica, may have the effect of discouraging our customers’ use of our frac sand and discouraging our insurers from covering this risk. The actual or perceived health risks of mining, processing and handling silica could adversely affect frac sand producers, including us, through reduced use of frac sand, the threat of product liability or employee lawsuits, increased scrutiny by federal, state and local regulatory authorities of us and our customers or reduced financing sources available to the silica industry.

Environmental and Occupational Health and Safety Regulations

Our operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection, compliance, 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 for non-compliance and may result in injunctive action. In certain circumstances, states have the option of adopting more stringent environmental standards and regulations than are implemented on the federal level. These laws and regulations may, for example, restrict the types, quantities and concentrations of various substances that can be stored, transported, disposed or 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, control, or remediate pollution from current or former operations. Also, these laws and regulations often require permits, authorizations, or licenses that impose operational restrictions and reporting obligations. 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 (“EHS”) 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 political and administrative changes, it is possible that there may be greater environmental, health and safety restrictions, particularly with regards to hydraulic fracturing, permitting, and greenhouse gas (“GHG”) emissions that may affect our operations. We have not experienced any material adverse effect from compliance with current EHS 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.

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 “special waste” or hazardous wastes in the future. Indeed, legislation has been proposed from time to time in the 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 exploration and production (“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 can include the current owner (or lessee) or operator of a contaminated facility, a former owner (or lessee) 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, and the costs of conducting certain health studies, among other things, is strict and joint and several. In the course of our operations, we use materials that, if released, could 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 engage in expensive litigation to defend the claims, and to allocate our proportionate share of liability, if any. Further, we may need to make significant expenditures to investigate and remediate such contamination under such laws, which could 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.

Some of our operations involve equipment containing regulated radioactive materials that require federal and/or state permits, reporting, testing and proper management practices. Any releases from that equipment may result in liability and/or an obligation to complete remediation and restoration.

Water Discharges. The Clean Water Act (“CWA”), Safe Drinking Water Act (“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. Federal and state laws and regulations may also regulate the discharge of stormwater or discharge to groundwater, often necessitating additional permits and design criteria. 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 and revisions under the Obama, Trump, and Biden administrations. On January 18, 2023, the EPA and the Corps finalized a revised definition of “Waters of the United States” to clarify the scope of federal regulatory authority under the CWA. However, in May 2023, the Supreme Court decided Sackett v. EPA, which significantly narrowed the scope of “waters of the United States” by holding that, under the CWA, the word “waters” refers only to geographical features that are described in ordinary parlance as “streams, rivers, oceans, and lakes” and adjacent wetlands that are indistinguishable from those bodies of water due to a continuous surface connection. As a result, on September 8, 2023, the EPA and the Corps finalized a rule amending the definition of “waters of the United States” to conform with the recent Supreme Court decision in Sackett. Litigation challenging the “waters of the United States” rule is ongoing. To the extent any rule or regulation expands the scope of the CWA’s jurisdiction, we and our customers could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. Additionally, many states have similar requirements that apply to state waters where federal jurisdiction ends, and as a result, under most circumstances, discharges of pollutants reaching any permanent waterbodies will likely be regulated.

Additionally, in April 2020, the Supreme Court decided County of Maui, Hawaii v. Hawaii Wildlife Fund, holding that discharges into groundwater may be regulated under the CWA if the discharge is the “functional equivalent” of a direct discharge into navigable waters. On November 27, 2023, the EPA issued draft guidance on whether a discharge via groundwater is a “functional equivalent” of a direct discharge, emphasizing that it is “highly dependent on site-specific considerations.”

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 or renewing 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 Clean Air Act (“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 and meet more stringent design criteria 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, the 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. Additional costs or delays incurred by our customers could adversely affect demand for the oil and natural gas they produce, which could reduce demand for our services.

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 the 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, and in November 2022, the EPA proposed a supplemental rule updating, strengthening and expanding its November 2021 proposal. The EPA issued a final rule on December 2, 2023, which includes New Source Performance Standards to reduce emissions of methane and other air pollutants from both new and existing oil and gas operations and emissions guidelines for states to follow in designing and executing implementation plans to cover existing sources (“Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources”). The regulations are likely to be subject to legal challenge and will also need to be incorporated into the individual state’s 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 GHG 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 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. Further, in 2022, the Biden Administration signed the Inflation Reduction Act (“IRA”) that committed to spending approximately $375 billion over a decade, primarily on promoting “clean energy,” in the form of incentives for solar and wind power and electric vehicles. In addition, for the first time ever, the IRA imposes a fee on methane emissions from certain facilities, including certain oil and gas facilities but provides for a conditional exemption from the fee if facilities are subject to and are in compliance with EPA methane regulations that are (1) in effect nationwide and (2) will “result in equivalent or greater emissions reductions as would be achieved” by the “Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources.” On January 12, 2024, the EPA issued a proposed rule to implement the IRA’s methane fee, which starts at $900 per metric ton of waste emissions in 2024, increasing to $1,200 for 2025, and $1,500 for 2026 and beyond, and only applies to emissions that exceed the statutorily specified levels. The proposed rule specifies how emissions are to be calculated and also includes criteria for certain flexibilities and exemptions. Additionally, in July 2023, the White House Council on Environmental Quality proposed amendments to the National Environmental Policy Act, as amended (“NEPA”), which include defining “effects” to include “climate change-related effects,” requiring agencies to consider climate change effects as part of the NEPA review process. The full impacts of these orders, pledges, agreements and any further legislation or regulation promulgated to fulfill the United States’ commitments under these initiatives 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, of oil and gas development on federal lands. In addition, in November 2022, the U.S. Bureau of Land Management (“BLM”) issued a proposed rule to reduce the waste of natural gas from venting, flaring and leaks during oil and gas production activities on federal and American Indian leases. For more information, see our regulatory disclosure below 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. On January 26, 2024, the Biden Administration announced a temporary pause on the U.S. Department of Energy’s review of pending decisions for authorization to export liquified natural gas (“LNG”) to non-Free Trade Agreement countries while the U.S. Department of Energy reviews and updates the underlying analyses for such decisions using more current data to account for considerations like the environmental and climate change impacts of LNG. The temporary pause is not expected to affect LNG exports that have already been authorized. Such developments could have an adverse effect on our business to the extent they result in decreased demand for LNG, which could result in a decrease in demand for our frac sand.

Additionally, on March 6, 2024, the SEC adopted new rules relating to the disclosure of a range of climate-related risks. At this time, we cannot predict the costs of implementation or any potential adverse impacts resulting from the rule. However, 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 canceling 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 Endangered Species Act (“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 Migratory Bird Treaty Act (“MBTA”) and various state analogs. The U.S. Fish & Wildlife Service (“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 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 taking of the species resulting from certain covered activities, including exploration and development of oil and gas fields. The conservation agreement 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. On June 30, 2023, the FWS proposed that the Dunes Sagebrush Lizard be listed as endangered under the ESA, and the comment period on the proposed rule ended on October 2, 2023.

On November 25, 2022, the FWS announced that the Northern distinct population segments (“DPS”) of the lesser prairie-chicken meets the definition of a threatened species and that the Southern DPS of the lesser prairie-chicken meets the definition of an endangered species. Therefore, FWS listed them as such and finalized a rule under the ESA, which became effective on January 24, 2023. Separately, following a lawsuit filed by conservation groups in 2021, the FWS made a decision to list the Missouri DPS of the eastern hell bender salamander as endangered under the ESA. Since October 2021, the Biden administration has proposed changes to regulations under the ESA, namely to the definition of “habitat” and a policy that made it easier to exclude territory from critical habitat. On November 30, 2022, the FWS reclassified the northern long-eared bat from a threatened species to an endangered species under the ESA, with an effective date of the redesignation of January 30, 2023. To the extent any protections are implemented or increased 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. 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. To date, the EPA has taken no further action in response to the 2016 report. 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 for such activities. The EPA also 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. 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. In addition, in November 2022, the BLM issued a proposed rule to reduce the waste of natural gas from venting, flaring and leaks during oil and gas production activities on federal and American Indian leases.

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 on August 18, 2022, a district court in the Western District of Louisiana permanently enjoined the moratorium as to the 13 states that filed a lawsuit against the implementation of the suspension. 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. However, in 2022, the IRA conditioned issuance of wind and solar rights-of-way on new oil and gas lease sales on federal land. There remains a significant uncertainty and increased regulatory risks and costs relating to onshore oil and 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 South Central Oklahoma Oil Province (“SCOOP”) and the Sooner Trend (oil field), Anadarko (basin) and Canadian and Kingfisher (countries) (“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 record keeping 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. We are also subject to OSHA’s standards for worker exposure to silica, which 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 administered by the DOL and 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. In June 2022, the MSHA launched a new enforcement initiative to better protect miners in the United States from health hazards resulting from repeated overexposure to respirable crystalline silica. MSHA administers and enforces the provisions of the Federal Mine Safety and 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. On July 13, 2023, the DOL issued a proposed rule amending its existing standards and setting a permissible exposure limit of respirable crystalline silica and including other requirements to protect miner health, such as exposure sampling, corrective actions to be taken when miner exposure exceeds the permissible exposure limit, and medical surveillance for miners.

Environmental Reviews. If permits or other authorizations from the federal government are required, our future operations may be subject to broad environmental review under NEPA. NEPA requires federal agencies to evaluate the environmental impact of all “major federal actions” significantly affecting the quality of the human environment. The granting of a federal permit for a major development project, such as a proppant production operations, may be considered a “major federal action” that requires review under NEPA. As part of this evaluation, the federal agency considers a broad array of environmental impacts, including, among other things, impacts on air quality, water quality, wildlife (including threatened and endangered species), historic and archeological resources, geology, socioeconomics and aesthetics. NEPA also requires the consideration of alternatives to the project. The NEPA review process, especially the preparation of a full environmental impact statement, can be time consuming and expensive. The purpose of the NEPA review process is to inform federal agencies’ decision-making on whether federal approval should be granted for a project and to provide the public with an opportunity to comment on the environmental impacts of a proposed project. Though NEPA requires only that an environmental evaluation be conducted and does not mandate a particular result, a federal agency could decide to deny a permit or impose certain conditions on its approval, based on its environmental review under NEPA, or a third party could challenge the adequacy of a NEPA review and thereby delay the issuance of a federal permit or approval, which could have an adverse effect on our business.

Availability of Information

Our website is located at http://www.pfholdingscorp.com. Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other reports and filings with the SEC are available free of charge on our website as soon as reasonably practicable after the reports are filed with or furnished to the SEC. Information contained on our website is not incorporated into this Annual Report or on our other filings with the SEC. Our filings are also available in hard copy, free of charge, by contacting us at 333 Shops Boulevard, Suite 301, Willow Park, Texas 76087, Attention: Investor Relations, telephone: (254) 776-3722. The SEC also maintains a website (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC. Additionally, we make available free of charge on our website:

Item 1A. Risk Factors.

We face various risks and uncertainties in the industry in which we operate and in the course of our business. Investors in our securities should carefully consider the following risk factors and all of the other information set forth or incorporated into this Annual Report. Additional risks and uncertainties not currently known to us, or that we currently deem immaterial, may also adversely affect our business, financial condition, results of operations, or cash flows.

Risks Related to our Growth Strategy

To achieve our growth and vertical integration objectives, our management relies on a rapid succession of strategic acquisitions, investments and procurement arrangements the pace and scope of which may have the potential to adversely affect the day-to-day operation of our business, and our cash flows, financial condition and results of operations.

Since the beginning of 2022, before the May 17th closing of our initial public offering and the start of trading of our Class A Common Stock on the Nasdaq Global Select Market (“Nasdaq”), we have aggressively pursued our growth and vertical integration strategies through a series of acquisitions, investments and procurement arrangements that increased our total assets from $664.6 million at December 31, 2021, to $3.1 billion at the end of fiscal year 2023. These acquisitions, investments and transactions include:

For a company of our size and resources, the pace and volume of the deal-making activity described above may create risks and uncertainties that can have a material adverse effect on the daily conduct of our business, and negatively impact our cash flows, financial condition and results of operations. For example, we are exposed to the risk that the day-to-day management, oversight, and operation of our business and our financial results may be adversely affected by:

In addition, because the historical utilization rates of any acquired assets may be lower than ours in recent periods, our utilization ratio could decrease during the course of an initial integration period. Accordingly, there can be no assurance the utilization for acquired assets will align with the utilization of our existing fleet or on our anticipated timeline or at all.

We have incurred and will continue to incur substantial indebtedness to finance acquisitions. We have also issued equity and may issue additional equity, 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.

Our growth and vertical integration objectives require substantial capital that we may be unable to obtain, or may only obtain at a cost or under terms that adversely affect our cash flows, financial condition and results of operations.

We have historically financed capital expenditures primarily with cash generated by operations, equipment and vendor financing, and borrowings under our credit facilities and other debt financing. As of the date of this annual report, however, the continued reliability of our traditional sources of funding has to be questioned. Any further disruptions or continuing volatility in the global financial markets (including as a result of a potential U.S. government default) may lead to additional increases in interest rates, or to a contraction in credit availability that could impair our ability to finance our operations and acquisitions. In the event our capital expenditure requirements at any time are greater than the amounts then available to us, we may not be able to obtain funding from such alternative sources of capital, and may be required to curtail or eliminate contemplated activities. Even if we can obtain capital from alternative sources, the terms of such fundings 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.

We may have difficulty managing growth in our business, which could adversely affect our financial condition and results of operations.

Growth in accordance with our business strategy, if achieved, could place a significant strain on our financial, operational and management resources. As we expand the scope of our activities and our geographic coverage through both organic growth and acquisitions, there will be additional demands on our financial, legal, accounting, technical, operational and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the failure to recruit and retain experienced managers and other professionals, could have a material adverse effect on our business, liquidity positions, financial condition, results of operations and prospects and our ability to successfully or timely execute our business strategy.

We may experience difficulties in integrating acquired assets into our business and in realizing the expected benefits of an acquisition.

The success of an acquisition, if achieved, will depend in part on our ability to realize anticipated business opportunities and benefits from combining the acquired assets with our business in an effective and efficient manner. The integration process could take longer than anticipated and could result in the loss of key employees, the disruption of each company’s ongoing businesses, tax costs or inefficiencies or inconsistencies in standards, controls, information technology systems, procedures and policies, any of which could adversely affect our ability to maintain relationships with customers, employees or third parties or our ability to achieve the anticipated benefits, and could harm our financial performance. If we are unable to successfully or timely integrate acquired assets with our business, we may incur unanticipated liabilities and be unable to realize the anticipated benefits, and our business, results of operations and financial condition could be materially and adversely affected.

Our indebtedness could adversely affect our financial flexibility and competitive position and make us more vulnerable to adverse economic conditions.

As of December 31, 2023, we had outstanding principal indebtedness of $1,107.9 million. See “Note 6 – Debt” in the notes to our consolidated financial statements for more details on our debt including the portion of our outstanding principal that matures in the year ending December 31, 2024. 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:

In addition, any failure to comply with the financial or other debt covenants could result in an event of default, which could result in some or all of our indebtedness becoming immediately due and payable. That occurrence would substantially and adversely affect our ability to continue operating our business and would severely and adversely affect our cash flows and financial condition and results.
 

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 debt agreements contain, and any future financing agreements we may enter into will likely contain, operating and financial restrictions and covenants that may restrict our ability to finance future operations or capital needs, or to engage in, expand or pursue our business activities. For example, our credit agreements restrict or limit our ability to:

Our compliance with these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures, finance acquisitions, equipment purchases and development expenditures, or withstand a future downturn in our business.

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 credit agreements, a significant portion of our indebtedness may become immediately due and payable. 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.

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.

We have exposure to increases in interest rates under certain of our debt agreements, some of which accrue interest at a variable rate. As a result, increases in interest rates could increase the cost of servicing such indebtedness and materially reduce our profitability, financial condition and cash flows.

We may not be able to generate sufficient cash flow to service all of our obligations, including our obligations under our credit and other financing facilities.

Our ability to make payments on and to upsize our current facilities, refinance any of our outstanding indebtedness, obtain additional financing, and to fund planned capital expenditures, strategic transactions and expansion efforts will depend on, among other things, our financial and operating performance, including, our ability to generate cash in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control.

Our business may not be able to generate sufficient cash flows from operations and collect our receivables, and there is no assurance that our future cash flows from operations will be sufficient to enable us to make payments due on our current or future indebtedness and to fund our other liquidity needs. If this is the case, we will need to refinance all or a portion of our indebtedness on or before maturity, and we cannot assure that we will be able to refinance any of our indebtedness in a timely manner, on commercially reasonable terms, or at all. We may need to implement one or more alternatives, such as reducing or delaying planned business activities, expenses and capital expenditures, selling assets, restructuring debt, or obtaining additional equity or debt financing. These financing strategies may not be executed on satisfactory terms, if at all or on terms that would be advantageous to our stockholders. Our ability to upsize our current facilities, refinance our indebtedness or obtain additional financing, and to do so on commercially reasonable terms, will depend on, among other things, our financial condition at the time, restrictions in agreements governing our indebtedness, and other factors, including the condition of the financial markets and the markets in which we will compete.

As a result of our debt refinancing transaction in December 2023, we are required to segregate collateral associated with Alpine Holding, LLC, PF Proppant Holdings, LLC and their respective subsidiaries and may have limited ability to access or use Alpine’s cash to satisfy our obligations or the obligations of our other subsidiaries. We also have limited ability to provide Alpine with liquidity to satisfy its obligations. See “Note 6 – Debt” in the notes to our consolidated financial statements for discussion of our debt financing.

If we do not generate sufficient cash flows from operations, and additional borrowings, refinancings or proceeds of asset sales are not available to us, we may not have sufficient cash to enable us to meet all of our obligations.
 

Risks Related to our Business

Our business and financial performance depends on the level of capital spending by oil and gas companies operating within the areas we service.

Demand for our services depends on the level of capital expenditures in the United States by companies in the oil and natural gas industry. 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. For example, the significant decline in oil and natural gas prices that followed the outset of the COVID pandemic in 2020 caused a reduction in our customers’ spending and associated drilling and

completion activities, all of which had an adverse effect on our revenue. While oil and natural gas prices have since increased, should prices decline again, similar declines in our customers’ spending would have an adverse effect on our revenue.

Numerous factors beyond our control affect our customers’ decisions regarding their level of exploration and production activity at any given time and, therefore, have an impact on the level of demand for our services at such time, including:

These factors, together with the historical tendency of oil and gas companies to increase production in response to price increases, which typically leads to overproduction and a collapse in prices, have often contributed to the volatility of the energy markets and the cyclical nature of the energy business.

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, each of our segments relies on specialized equipment, parts and raw materials supplied by third parties 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 stimulation services. Similarly, our manufacturing business relies on a limited number of suppliers for major equipment to build our new electric-powered hydraulic fracturing fleets utilizing Clean Fleet® technology.

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, or in the time needed to upgrade our fleet, could have a material adverse effect on our business, financial condition, results of operations and cash flows.

In addition, future price increases for the equipment, parts and raw materials we purchase from others could negatively impact our ability to update or expand our existing fleets, to timely repair equipment in our existing fleets or meet the demands of our customers.

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

The majority of our revenue is generated from the provision of hydraulic fracturing services to a discrete number of recurring customers. During the fiscal years ended on December 31, 2023, 2022 and 2021, our top ten customers represented, respectively, 41%, 35% and 63% of our consolidated revenues.

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.

As a vertically integrated company, our proppant production segment makes significant intercompany sales to our stimulation services segment and could be adversely affected if our stimulation services segment fails to perform as expected.

Oil and natural gas companies’ operations using hydraulic fracturing are substantially dependent on the availability of water, as are our frac sand mining and processing operations. Restrictions on the ability to obtain water and the disposal of flowback and produced water may impact their and our 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 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.

The frac sand excavation and processing activities in which we engage also require significant amounts of water, of which we seek to recycle a significant percentage in our operating process. As a result, securing water rights and water access to sufficient volumes of water and obtaining water discharge permits where required are necessary for the operation of our processing facilities.

Our frac sand operations are dependent on our rights and ability to mine our properties and on our having received or renewed the required permits and approvals from governmental authorities and other third parties.

We currently hold, and will seek, numerous environmental, mining and other permits from governmental authorities, as well as water rights and approvals authorizing our frac sand operations. For our extraction and processing, the permitting process is governed by to federal, state, and local laws and regulations. For example, on the federal level, a Mine Identification Request (MSHA Form 7000-51) must be filed and obtained before mining commences. If wetlands are implicated, a wetlands permit may be required from the U.S. Army Corps of Engineers (the “Corps”). At the federal and state level, a series of permits and approvals are required related to air quality, wetlands, water quality (wastewater and stormwater), grading permits, threatened and endangered species, archaeological assessments and high capacity wells in addition to others depending upon site-specific factors and operational detail. At the local level, mining, zoning, building, stormwater, erosion control, road usage and access, among other matters, may be regulated and require permitting or approval from local governmental authorities. For example, Aggregate Production Operations permits are required for our Texas production facilities and similar permits may be required for our facilities in other states. A decision by a governmental agency or other third party to deny or delay issuing a new or renewed permit or approval, or to revoke or substantially modify an existing permit or approval, could have a material adverse effect on our ability to commence or continue related operations.

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. Legal challenges claiming that we do not have title to our property or lack appropriate water rights could cause us to lose any rights to explore, develop and extract minerals without

compensation for our prior expenditures relating to such property. Our business may suffer a material adverse effect in the event that any such claims are successful.

In some instances, we have received access rights or easements from third parties, which allow for more efficient operations. Such third party could take legal action to restrict or suspend the access or easement or could refuse to renew such rights or easements upon their contractual expiration, which could be materially adverse to our business, results of operations or financial condition.

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 (including fracturing fluids, and chemical additives). In addition, our operations are exposed to potential natural disasters, such as 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.

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.

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 Financial Officer and Chief Legal 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.

We rely on contractors to conduct a significant portion of our frac sand mining operations.

A significant portion of our frac sand mining operations are currently conducted in whole or in part by contractors, including services from related parties. Contractors provide us mining, wet and dry loading and hauling services at our Kermit Sand Mine, Lamesa Sand Mine, Monahans Sand Mine, San Antonio Sand Mine and Merryville Sand Mine, and provide us certain related equipment. Wilks Earthworks, LLC (“Earthworks”), an affiliate of the Wilks Parties, provides us those services at our Kermit Sand Mine, Lamesa Sand Mine and San Antonio Sand Mine pursuant to a Master Services Agreement dated effective as of December 1, 2022 (the “Earthworks Services Agreement”). The term of the agreement expires on December 1, 2024 and renews automatically for successive one year terms unless earlier terminated. As a result of these arrangements, our operations are subject to a number of risks, some of which are outside our control and may negatively affect our operations and financial results, including:

Inaccuracies in our estimates of frac sand 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 frac sand 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, frac sand 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 frac sand reserves and resources, many of which are beyond our control and any of which could cause actual results to differ materially from our expectations. These uncertainties include:

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, at our Kermit Sand Mine, a portion of our 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.

Our frac sand mining operations are dependent on our rights and ability to mine our properties and on our having received or renewed the required permits and approvals from governmental authorities and other third parties. A decision by a governmental agency or other third party to deny or delay issuing a new or renewed permit or approval, or to revoke or substantially modify an existing permit or approval, could have a material adverse effect on our ability to commence or continue related operations.

In some instances, we have received access rights or easements from third parties, which allow for more efficient operations. Such third party could take legal action to restrict or suspend the access or easement or could refuse to renew such rights or easements upon their contractual expiration, which could be materially adverse to our business, results of operations or financial condition.

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 typically 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 occurring below grade. We may have liability in such cases to the extent we were found to be grossly negligent or having committed 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. This reciprocal or mirrored indemnity and risk allocation model is known as knock for knock indemnity and is common in oilfield services agreements. 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 ProFrac 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.

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

If we are not able to protect our patents or 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 ensure that any patents we currently own or 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.

If we fail to respond to our customers’ growing demand for environmentally sensitive equipment, our business will be adversely affected.

As our customers have become more focused on the reductions of their emissions footprint, we have introduced products and services (such as our electric-powered hydraulic fracturing fleets) to meet their needs. As of December 31, 2023, approximately 75% of our pumps rely on electric frac or natural gas burning engine technology (which we consider to be currently the most environmentally friendly available technologies used in our industry). In addition to being less attractive to customers, the legacy portion of our fleet is less efficient, and often requires additional maintenance and capital expenditures to be kept in good operating condition and may, therefore, be subject to longer or more frequent periods of unavailability.

If we fail to upgrade and replace our fleet with the higher efficiency and more environmentally friendly equipment the industry increasingly demands, our competitive position may deteriorate, which may have a material adverse effect on our financial position, results of operations and cash flows.

Our financial results may be materially adversely affected by the inclusion of Flotek’s financial statements in our consolidated financial statements, and we do not have the benefit of Flotek’s cash or liquidity.

Due to our determination that Flotek is a variable interest entity of which ProFrac is the primary beneficiary, Flotek’s financial statements have been included in our consolidated financial statements from May 17, 2022. Consequently, our financial results may be materially adversely affected if Flotek reports poor or worsened financial results. Any delays in Flotek’s reporting of its financial results or material inaccuracies in Flotek’s financial statements could negatively impact ProFrac’s ability to timely or accurately report its financial results. In addition, we do not have the ability to access or deploy Flotek’s cash or liquidity in our operations, which may limit our ability to mitigate the impact of the inclusion of Flotek’s financial statements in our consolidated financial statements.

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.

We and our customers are subject to a variety of federal, state and local environmental laws and regulations affecting the hydraulic fracturing and mining and mineral processing industry, including, among others, those relating to employee health and safety, environmental permitting and licensing, plant and wildlife protection, wetlands protection, air and water emissions, greenhouse gas emissions, water pollution, waste management, including the transportation and disposal of waste and other materials, remediation of soil and groundwater contamination, land use, reclamation and restoration of properties, hazardous materials and natural resources. These laws and regulations have imposed, and will continue to impose, numerous obligations on our operations and the operations of our customers, including the acquisition of permits or other approvals to conduct regulated activities, the imposition of restrictions on the types, quantities and concentrations of various substances that may be released into the environment, the incurrence of capital expenditures to mitigate or prevent releases of hazardous materials from our equipment and facilities, and the application of specific health and safety criteria addressing worker protection. Some environmental laws impose substantial penalties for noncompliance, and others, such as the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), impose strict, retroactive and joint and several liability for the remediation of releases of hazardous substances. 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 owners or operators or other third parties without regard to fault or the legality of the conduct at the time. Governmental agencies, citizen organizations, 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. In addition, any failure by us to comply with applicable laws and regulations may cause governmental authorities to take actions that could adversely impact our operations and financial condition, including:

Costs associated with compliance with these laws, defending against related claims, and any actual liabilities have been and will continue to be significant. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly pollution control equipment and operations, the occurrence of delays in the permitting or performance of projects, or waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our financial position and results of operations.

Changes in laws or government regulations could increase our costs of doing business.

Environmental, health and safety laws and regulations are constantly evolving, and they may change or become more stringent in the future. 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 capital and operating expenditures.

New and existing regulatory disclosure requirements may implicate our trade secrets and cause us competitive harm if such trade secrets become public.

Many states in which we operate require the disclosure of some or all the chemicals used in our pressure pumping operations. Certain aspects of one or more of these chemicals may be considered proprietary by us or our chemical suppliers. Disclosure of our proprietary chemical information to third parties or to the public, even if inadvertent, could diminish the value of our trade secrets or those of our chemical suppliers and could result in competitive harm to us, which could have an adverse impact on our business, financial condition, prospects and results of operations.

Supply chain issues, moratoriums, and increased regulatory requirements on our suppliers may impact the cost and availability of raw materials necessary to our operations.

Our business could be affected by moratoriums or increased regulation of other companies in the supply chain, such as sand mining by our proppant suppliers, or our chemical suppliers, which could limit our access to supplies and increase the costs of raw materials. At this time, it is not possible to estimate how these various restrictions could affect our ongoing operations.

Our operations, and those of our customers, are subject to a series of risks arising from climate change, which ultimately may result in increased GHG regulation, decreased demand for fossil fuels, and fewer oil and gas permits and licenses, all of which may affect our operations and profitability.

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 significant public investment in zero-carbon energy production and storage, consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. The risk of these continued efforts to drive down carbon emissions may result in reduced business opportunities and profitability.

As a result of increased attention to combating climate change, various governmental and non-governmental groups have pledged to achieve reductions to GHG emissions. One recent development in this area, the 2022 IRA, discussed above, involves significant investment over the next 10 years into solar and wind energy production and battery storage infrastructure in an effort to reduce U.S. GHGs to about 40 percent lower than 2005 levels by 2030. Such significant public investment in non-fossil fuel energy production may reduce demand for traditional fossil fuel electricity production which could negatively impact prices of natural gas and profitability of our operations.

The regulation of methane from oil and gas facilities stands to become more restrictive under the current federal administration. The EPA already imposes limitations on methane emissions from new sources in the oil and gas sector through NSPS and the EPA’s final rule, announced on December 2, 2023, reduces emissions of methane and other air pollutants from both new and existing oil and natural gas operations and provides emissions guidelines for states to follow in designing and executing implementation plans to cover existing sources. Such regulation of methane emission for new sources and the promulgation of further requirements for existing oil and gas customers could result in increased operational costs and adversely affect demand for our products and services. The complete impacts of these pledges, investments, agreements, and the legislation or regulation promulgated to fulfill the United States’ commitments to reduce GHG emissions, cannot be predicted at this time. Additionally, we cannot predict any future reductions and restrictions beyond what is currently proposed.

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. Such litigation against our customers could reduce the demand for our products and services, which could have a material adverse effect on our business, financial condition and results of operation.

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. 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. In 2021, President Biden signed an executive order calling for the development of a “climate finance plan” and, separately, the Federal Reserve announced that it had 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, which could reduce the demand for our services and products and have a material adverse effect on our business, financial condition and results of operation.

Additionally, political, litigation and financial risks may result in our customers restricting or canceling production activities, incurring liability for infrastructure damages as a result of climate change, or impairing their ability to continue to operate in an economic manner, which also could reduce the demand for our services and products. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.

Finally, many scientists have concluded that increasing concentrations of GHG in the atmosphere may have significant physical climate effects, such as increased frequency and severity of storms, droughts, and floods and other climate events that could have an adverse effect on our and 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. As discussed above, hydraulic fracturing is generally exempt from federal regulation under 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. Increased federal regulation of fracking operations would likely lead to increased compliance costs and a higher probability of enforcement actions and litigation.

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.

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 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, as discussed above, the increased competitiveness and investment into non-fossil fuel energy sources (such as wind, solar, geothermal, hydrogen, tidal, battery storage technologies, 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 hydrocarbon fuels and our services, which would lead to a reduction in our revenues.

Oilfield anti-indemnity provisions enacted by many states may restrict or prohibit a party’s indemnification of us.

We typically enter into agreements with our customers governing the provision of our services, which usually include certain indemnification provisions for losses resulting from operations. Such agreements may require each party to indemnify the other against certain claims regardless of the negligence or other fault of the indemnified party; however, many states place limitations on contractual indemnity agreements, particularly agreements that indemnify a party against the consequences of its own negligence. Furthermore, certain states, including Louisiana, New Mexico, Texas, and Wyoming, have enacted statutes generally referred to as “oilfield anti-indemnity acts” expressly prohibiting certain indemnity agreements contained in or related to oilfield services agreements. Such oilfield anti-indemnity acts may restrict or void a party’s indemnification of us, which could have a material adverse effect on our business, financial condition, prospects, and results of operations.

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. For example, the US Consumer Product Safety Commission has raised concerns about the potential for certain indoor gas appliances to emit harmful quantities of certain air pollutants. The impact of the changing demand for oil and natural gas services and products, and proposed laws and regulations, may have a material adverse effect on our business, financial condition, results of operations and cash flows.

The commercial development of economically viable non-fossil fuel 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 by 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 reduce demand for our products and services and 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 ESA restricts activities that may affect endangered or threatened species or their habitats and similar protections are offered to migratory birds under the MBTA and other federal and state statutes. To the extent species that are listed and protected under the ESA or similar state laws, or 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 and mining 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 or the designation of previously unidentified species in the areas where we or our customers operate similarly has the potential to adversely impact our operations and the operations of our customers, including by causing our operations to become subject to operating restrictions or bans and limiting future development activity in affected areas. Changes to existing rules could increase the portion of our or our customers’ operating areas that could be designated as critical habitat. Such new species designations or more restrictive rules could materially restrict use of or access to federal, state and private lands.

For example, on July 3, 2023, the FWS proposed that 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 we and our customers operate), be listed as endangered under the ESA. The comment period on the proposed rule ended on October 2, 2023. At this time, we cannot be sure of the precise potential effects of such proposed listing, if it is finalized, on our or our customers’ operations. However, as discussed above, a decision by the FWS to list the Dunes Sagebrush Lizard as endangered could subject us and our customers to operating restrictions and/or limit areas of our current or future operations. The FWS has not yet proposed to designate critical habitat for the Dunes Sagebrush Lizard, which it may do so up to a year after a listing under the ESA. At this time, the effects of such designation on our or our customers’ operations or the operations of our peers are likewise uncertain.

Silica-related health issues and legislation, including compliance with existing or future regulations relating to respirable crystalline silica, or litigation could have an adverse effect on our business, reputation or results of operations.

We are subject to laws and regulations relating to human exposure to crystalline silica. For example, the federal Occupational Safety and Health Act (“OSHA”) has implemented rules establishing a more stringent permissible exposure limit for exposure to respirable crystalline silica and provided other provisions to protect employees. These rules require compliance with engineering control obligations to limit exposures to respirable crystalline silica in connection with hydraulic fracturing activities. In June 2022, the Department of Labor’s (“DOL”) Mine Safety and Health Administration (“MSHA”) launched a new enforcement initiative to better protect U.S. miners from health hazards resulting from repeated overexposure to respirable crystalline silica. MSHA reports that silica dust affects thousands of miners each year and, without adequate protection, miners face risks of serious illnesses, many of which can be fatal. On July 13, 2023, the MSHA issued a proposed rule amending its existing standards and setting a permissible exposure limit of respirable crystalline silica.

As part of the DOL’s program, MSHA will conduct silica dust-related mine inspections and expand silica sampling at mines, while providing mine operators with compliance assistance and best practices to limit miners’ exposure to silica dust.

Specifically, the silica enforcement initiative will include:

In addition, the DOL’s Educational Field and Small Mine Services staff will provide compliance assistance and outreach to mine operators, unions and other mining community organizations to promote and advance protections for miners. The MSHA initiative is intended to take immediate action to reduce the risks of silica dust exposure as the DOL’s development of a mining industry standard continues.

If we are unable to satisfy these obligations, or are not able to do so in a manner that is cost effective or attractive to our customers, our business operations may be adversely affected or availability or demand for our frac sand could be significantly affected. Federal and state regulatory authorities, including OSHA, MSHA and analogous state agencies, may continue to propose changes in their regulations regarding workplace exposure to crystalline silica, such as permissible exposure limits and required controls and personal protective equipment, and we can provide no assurance that we will be able to comply with any future laws and regulations relating to exposure to crystalline silica that are adopted, or that costs of complying with such future laws and regulations would not have an adverse effect on our operating results by requiring us to modify or cease our operations.

In addition, the inhalation of respirable crystalline silica is associated with health risks, including the lung disease silicosis. There is evidence of an association between crystalline silica exposure or silicosis and lung cancer and possible association with other diseases, including immune system disorders such as scleroderma. These health risks have been, and may continue to be, a significant issue confronting the hydraulic fracturing industry. Concerns over silicosis and other potential adverse health effects, as well as concerns regarding potential liability from the use of frac sand, may have the effect of discouraging our customers’ use of frac sand. The actual or perceived health risks of handling frac sand could adversely affect hydraulic fracturing service providers, including us, through reduced use of frac sand, the threat of product liability or employee lawsuits naming us as a defendant, increased scrutiny by federal, state and local regulatory authorities of us and our customers or reduced financing sources available to the hydraulic fracturing industry.

Over the past few decades, a number of companies that utilize silica in their operations have been named as a defendant, usually among many defendants, in product liability lawsuits brought by or on behalf of current or former employees or customers alleging damages caused by silica exposure. The silica- related litigation brought against us to date, and associated litigation costs, settlements and verdicts, have not resulted in a material liability to us, and we presently maintain insurance policies where available. However, we may continue to have silica exposure claims filed against us in the future, including claims that allege silica exposure for periods or in areas not covered by insurance, and the costs, outcome and impact to us of any pending or future claims is not certain. Any such pending or future claims or inadequacies of our insurance coverage could have a material adverse effect on our business, reputation, financial condition and results of operations.

Risks related to our Corporate Structure and our Class A Common Stock

The Issuer is a holding company and its only material asset is its equity interest in ProFrac LLC; accordingly the Issuer is entirely dependent upon distributions from ProFrac LLC to meet its obligations, including the payment of taxes and covering its corporate and other overhead expenses.

The Issuer, ProFrac Holding Corp., is a holding company that has no material assets other than its equity interest in ProFrac LLC and, accordingly, has no independent means of generating revenue. To the extent ProFrac LLC has available cash, it is required to make (i) generally pro rata distributions to the holders of Units, including the Issuer, in an amount at least sufficient to allow the Issuer to pay its taxes (and those of its wholly owned subsidiaries) and to make payments under the Tax Receivable Agreement and any subsequent tax receivable agreement that it may enter into in connection with future acquisitions and (ii) non-pro rata payments to the Issuer to reimburse it for its corporate and other overhead expenses. If the Issuer needs funds, and ProFrac LLC or its subsidiaries are unable to provide such funds, or are restricted from doing so by applicable law or regulation or by the terms of any current or future financing arrangements, there is no assurance that the Issuer will be able to secure funds from other sources.

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 distributions is 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.

Conflicts of interest could arise between us, on the one hand, and Dan Wilks and Farris Wilks and entities owned by or affiliated with them (collectively, the “Wilks Parties”), on the other hand, concerning among other things, business transactions, competitive business activities or business opportunities.

Conflicts of interest could arise between us, on the one hand, and the Wilks Parties, on the other hand, concerning among other things, business transactions, competitive business activities or business opportunities. The Wilks Parties operate in the energy and oilfield services industries. In the normal course of business, we have engaged in transactions with some of these companies. Furthermore, the Wilks Parties now, and in the future may, directly or indirectly, compete with us for investment or business opportunities.

The Wilks Parties are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us and do 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.

The Wilks Parties 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 opportunities. In addition, the Wilks Parties 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, 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 the Sarbanes-Oxley Act of 2002 (“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 are required to comply with laws, regulations and requirements, including certain corporate governance provisions of Sarbanes-Oxley, and regulations of the Securities and Exchange Commission (“SEC”) and the requirements of Nasdaq. Complying with these statutes, regulations and requirements has and will continue to occupy a significant amount of time of our board of directors and management and significantly increase our costs and expenses. We are required to:

Section 404 of Sarbanes-Oxley requires that, upon satisfaction of certain conditions, our management assess the effectiveness of our internal control over financial reporting, and our independent registered public accounting firm issue an attestation report on those internal controls. Compliance with these provisions is onerous, and there is no assurance that we will be in a position to meet these legal requirements when they become applicable to us, 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.

Our stock price may be volatile, which could lead to losses by investors.

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 ProFrac’s control. For example, since we consummated our IPO, the closing sales price of our Class A Common

Stock has fluctuated from a high of $25.72 per share on November 22, 2022, to a low of $6.73 per share on February 14, 2024.

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

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 current market price of our securities may not be indicative of future market prices or intrinsic value, and we may not be able to sustain or increase the value of an investment in our securities. Investors in our securities may experience a decrease, which could be substantial, in the value of their securities, including decreases unrelated to our operating performance, financial results or prospects. Your only opportunity to achieve a return on your investment in our securities may be if the market price of our securities appreciates and you sell your securities at a profit. The market price for our securities may never exceed, and may fall below, the price that you paid for such securities. You could lose all or part of your investment in us as a result.

The Wilks Parties 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.

As of December 31, 2023, the Wilks Parties controlled approximately 84.4% of our total voting power. As a result, the Wilks Parties are 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 Parties 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 Parties 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. Certain Wilks Parties hold all of our Series A Preferred Stock, which could cause their interests to differ. 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 Parties which may differ from the considerations of us or our other stockholders.

Furthermore, in connection with our IPO, ProFrac entered into a Stockholders’ Agreement, dated as of May 17, 2022, with certain of the Wilks Parties (as amended on January 13, 2023, the “ProFrac Stockholders’ Agreement”), which addresses the right to designate nominees for election to the ProFrac board of directors. 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 ProFrac’s other stockholders to approve transactions that they may deem to be in the best interests of ProFrac. Moreover, the Wilks Parties’ concentration of stock ownership may adversely affect the trading price of ProFrac Class A Common Stock to the extent investors perceive a disadvantage in owning stock of a company with significant stockholders.

A significant reduction by the Wilks Parties of their ownership interests in ProFrac could adversely affect us.

We believe that the Wilks Parties’ substantial ownership interest in ProFrac provides them with an economic incentive to assist us to be successful. However, the Wilks Parties may elect at any time to sell all or a substantial portion of or otherwise reduce their ownership interest in us. If the Wilks Parties sell all or a substantial portion of their ownership interests in us, they may have less incentive to assist in our success. Such actions could adversely affect our ability to successfully implement our business strategies which could adversely affect our cash flows or results of operations.

The issuance of Class A Common Stock upon the conversion of the Series A Preferred Stock may cause dilution to our existing stockholders.

Following the first anniversary of the first issuance of shares of Series A Preferred Stock, our Series A Preferred Stock is convertible into our Class A Common Stock at a conversion ratio that is the quotient of: (i) the liquidation preference as of the date of the conversion and (ii) the then applicable conversion price (which is initially set at $20.00, but may be adjusted from time to time, in accordance with the terms of the Series A Certificate of Designation). It is likely that a larger amount of our Class A Common Stock will be issued the further into the future that our Series A Preferred Stock is converted into our Class A Common Stock. The Series A Preferred Stock is entitled to 8% dividends per annum, paid-in-kind and compounded quarterly on the then outstanding Liquidation Preference (as defined in the Series A Certificate of Designation). See “Note 8 – Preferred Stock” in the notes to our consolidated financial statements for additional information. We cannot predict when, and how many, shares of our Class A Common Stock shall be issued upon the conversion of the Series A Preferred Stock, or predict or quantify any dilution existing holders of our Class A Common Stock may experience upon such conversion. The conversion of the Series A Preferred Stock into our Class A Common Stock could result in substantial dilution to existing holders of our Class A Common Stock. Holders of our Series A Preferred Stock also have liquidation rights that could affect the residual value of the Class A Common Stock.

Our certificate of incorporation and bylaws, as well as Delaware law, 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 certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval (other than the approval in certain circumstances of the holders of the Series A Preferred Stock) 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 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 in addition to the Series A Preferred Stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our certificate of incorporation and 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, for example, the following:

In addition, as a Delaware corporation we are governed by the Delaware General Corporation Law (as the same may be amended hereafter, the “DGCL”). In general, Section 203 of the DGCL, an anti-takeover law, prohibits a publicly held Delaware corporation from engaging in a business combination (as defined in Section 203 of the DGCL), such as a merger, with a person or group owning 15% or more of a company’s voting stock, which person or group is considered an interested stockholder under the DGCL, for a period of three years following the date the person became an interested stockholder, unless (with certain exceptions) the business combination or the transaction in which the person became an interested stockholder is approved in a prescribed manner. We have elected in our certificate of incorporation not to be subject to Section 203.

Our certificate of incorporation designates 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 certificate of incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware, 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 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 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. Investors in shares of our capital stock are bound by these provisions which 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, these choice of forum limitations do 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.

We do not presently anticipate paying cash dividends on our Class A Common Stock and our existing debt agreements, as well as the Series A Certificate of Designation, place restrictions on our ability to do so. Consequently, your only opportunity to achieve a return on your shares of Class A Common Stock is if the price of our Class A Common Stock appreciates.

While we look forward to the opportunity to pay dividends in the future, we do not presently anticipate paying any cash dividends on our Class A Common Stock in the foreseeable future. In addition, our Series A Certificate of Designation and our existing debt agreements place, and we expect our future debt agreements will place, restrictions on our ability to pay cash dividends. Consequently, unless we revise our dividend policy, receive permission from the holders of our Series A Preferred Stock pursuant to the Series A Certificate of Designation, and are released of the provisions in our loan agreements that restrict the payment of dividends, 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 the price that 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 amount that you paid for it.

The price of our Class A Common Stock may decline as a result of the large number of shares available for sale.

As of December 31, 2023, we had 159,388,841 shares of our Class A Common Stock outstanding, and approximately 2,542,708 shares of Class A Common Stock remained available for issuance under our long-term incentive plan. The Wilks Parties owned 134,458,994 shares of our outstanding Class A Common Stock at March 11, 2024. Under the Registration Rights Agreement dated as of May 17, 2022 by and among ProFrac and certain of the Wilks Parties, the Wilks Parties have registration rights in accordance with which ProFrac must file a registration statement for resale of all the shares of Class A Common Stock held by the Wilks Parties. In addition, the price of the Class A Common Stock may decline as a result of the conversion of the outstanding Series A Preferred Stock into Class A Common Stock. All of these shares are subject to the rights of the holders thereof to require ProFrac to file a registration statement for their resale.

The fact that many or all of these unissued shares may become issued and available for resale on very short notice may adversely affect the price at which our Class A Common Stock trades. In addition, we may issue in the future additional shares of our Class A Common Stock, or securities convertible into Class A Common Stock, which may further adversely affect the trading price of our shares and dilute existing shareholders.

ProFrac Holding Corp. is 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.

We are party to the Tax Receivable Agreement with the TRA Holders. This agreement generally provides for the payment by ProFrac 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 actually realizes (or is deemed to realize in certain circumstances) in periods after our IPO as a result of certain increases in tax basis available to ProFrac as a result of acquisitions of Units in connection with the IPO or pursuant to the exercise of the Redemption Right or the Call Right (as such terms are defined in the ProFrac LLC Agreement) 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 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 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 Units, which occurred in April 2023, see “Item 1. Business – 2023 Significant Events - Redemption of ProFrac LLC Units” for additional information.

The payment obligations under the Tax Receivable Agreement are our 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 our 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 we would have been required to pay had we 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 amount and timing of taxable income we generate in the future, the U.S. federal income tax rates then applicable, and the portion of our 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 in order to enable us to make payments under the Tax Receivable Agreement, as well as any corresponding pro rata distributions made to the Unit Holders, could have an adverse impact on our liquidity.

The payments under the Tax Receivable Agreement are not conditioned upon a TRA Holder having a continued ownership interest in ProFrac or ProFrac LLC. For more information, see “Note 11 – Income Taxes” in the notes to our consolidated financial statements for more information.

In certain cases, payments under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits, if any, we realize 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), our obligations under the Tax Receivable Agreement would accelerate and we 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 we have sufficient taxable income to fully utilize the tax benefits covered by the Tax Receivable Agreement, and (ii) that any Units (other than those held by ProFrac) 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, our 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 had otherwise been terminated at December 31, 2023, the estimated termination payments could range up to more than $70 million. 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.

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), we 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 are not conditioned upon the TRA Holders’ having a continued interest in ProFrac or ProFrac LLC. Accordingly, the TRA Holders’ interests may conflict with those of the holders of our Class A Common Stock.

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 our actual cash tax savings, if any, and we may not be able to recoup those payments, which could materially adversely affect our liquidity.

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

Our certificate of incorporation authorizes us to issue, without the approval of our stockholders (other than the approval of the holders of the Series A Preferred Stock in certain circumstances), one or more classes or series of preferred stock in addition to our outstanding Series A Preferred Stock having the designations, preferences, limitations and relative rights, including preferences over our Class A Common Stock respecting dividends and distributions, that 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 our Class A Common Stock, as they have with the currently outstanding Series A Preferred 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, the Issuer controls and operates ProFrac LLC. On that basis, we believe that the Issuer’s interest in ProFrac LLC is not an “investment security” as that term is used in the 1940 Act. However, if the Issuer were to cease participation in the management of ProFrac LLC, its interest in ProFrac LLC could be deemed to be an “investment security” for purposes of the 1940 Act.

Although the Issuer and ProFrac LLC intend to continue to conduct their operations so that the Issuer will not be deemed an investment company, if the Issuer 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, would make it impractical for us to continue our business as contemplated and would have a material adverse effect on our business, financial condition and results of operations.

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

Because the Wilks Parties beneficially own 134,458,994 shares of our Class A Common Stock, representing approximately 84.4% of the voting power of ProFrac as of December 31, 2023, we are a controlled company under Sarbanes-Oxley and rules of Nasdaq. Additionally, the Wilks Parties are currently, and we expect that they will continue to be, deemed a group for purposes of certain rules and regulations of the SEC as a result of the ProFrac 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:

These requirements will not apply to us as long as we remain a controlled company. We currently intend to continue 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.

General Risk Factors

Our business could be adversely affected by a decline in general economic conditions or a weakening of the broader energy industry, and inflation may adversely affect our financial position and operating results.

A prolonged economic slowdown or recession, adverse events relating to the energy industry, or regional, national or global economic conditions and factors, particularly a slowdown in the E&P industry, could negatively impact our operations and therefore adversely affect our results. The risks associated with our business are more acute during periods of economic slowdown and recession because such periods may be accompanied by decreased exploration and development spending by our customers, decreased demand for oil and natural gas, and decreased prices for oil and natural gas.

Inflationary factors, such as increases in the labor costs, material costs, and overhead costs, may also adversely affect our financial position and operating results.

Developments related to the ongoing wars between Russia and Ukraine and between Israel and Hamas, and the global response thereto, could adversely affect our business, financial condition and results of operations.

Russia is one of the main players in the global oil markets. Accordingly, any events that can impair or enhance its ability to compete in such markets are likely to have an impact on the industry in which we operate, the business decisions of our customers, and the level of demand for our services. Since the beginning of the war between Russia and Ukraine, sanctions imposed by Ukraine’s allies that seek to limit Russia’s ability to profit from oil and gas exports, and certain of the retaliatory measures taken by Russia in response (such as the ban on sales to certain countries), have created conditions resulting in an

increased demand for our services. There is no assurance that such conditions will continue to exist, and even if they do, that we will continue to be able to benefit from them. The potential effects of the ongoing war between Israel and Hamas could also impact the industry in which we operate, the business decisions of our customers, and the level of demand for our services.

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. 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 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.

We face significant competition that may cause a loss of 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. Numerous factors could cause us to lose our competitive position, including the nature of the markets we compete in, and the often-times price-based nature of the competition we face.

The market for hydraulic fracturing services is fragmented and includes, not only numerous small companies capable of competing effectively in our markets on a local basis, but also several large companies that possess substantially greater financial and other resources than we do. Our larger competitors’ greater resources could allow them 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 to 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, and we have had in the past to lower our prices to remain competitive. For example, because of a combination of the increased competition which began during the second half of 2018 and 2019 and the decreased demand for our services in 2020 due to the COVID-19 pandemic, we had to lower our prices to remain competitive, which contributed to a 35% decrease in revenues from stimulation services for fiscal year 2020 (as compared to 2019). Although our industry and results of operations have seen a strong recovery since those times, the vitality characteristic of the energy business makes it impossible for us to rule out potential adverse changes in the competitive landscape that may force us, once again, to lower our prices, which would adversely affect our results of operations. In addition, 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 also have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our wealthier 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.

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 operations and ability to raise capital.

Certain segments of the investor community have developed negative sentiment towards investing in our industry. For example, 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 lenders and investors to stop financing oil and gas production and related infrastructure projects, which adversely affects our customers. Such developments 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.

Negative public perception can lead to additional regulatory burdens and reduced business opportunities for us.

Increasing attention to climate change and natural capital, societal expectations on companies to address climate change, investor and societal expectations regarding voluntary ESG initiatives and disclosures, and consumer demand for alternative sources of energy may result in increased costs (including but not limited to increased costs associated with compliance, stakeholder engagement, contracting, and insurance), reduced demand for our customers’ hydrocarbon products and our product and services, reduced profits, increased legislative and judicial scrutiny, investigations and litigation, and negative impacts on our stock price and access to capital markets. Negative public perception regarding the oil and natural gas 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 and other advocacy groups may oppose our or our customers’ operations through organized protests, attempt 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 and our customers’ assets. These actions may increase our costs and reduce our customers’ production levels over time which, as a result, may reduce demand for our products and 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 we or our customers require to conduct operations to be withheld, delayed or burdened by requirements that restrict our or our customers’ ability to profitably conduct business. Ultimately, this could make it more difficult to secure funding for our operations.

Voluntary disclosures regarding ESG matters, as well as any ESG disclosures mandated by law, could result in private litigation or government investigation or enforcement action regarding the sufficiency or validity of such disclosures. In addition, failure or a perception (whether or not valid) of failure to implement ESG strategies or achieve ESG goals or commitments, including any GHG reduction goals or commitments, could result in governmental investigations or enforcement, private litigation and damage our reputation, cause our investors or consumers to lose confidence in our Company, and negatively impact our operations. While we may create and publish disclosures regarding ESG matters, many of the statements in those disclosures may be based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying and measuring many ESG matters. Such disclosures may also be partially reliant on third-party information that we have not or cannot independently verify. Additionally, we expect there will likely be increasing levels of regulation, disclosure-related and otherwise, with respect to ESG matters, and increased regulation will likely to lead to increased compliance costs as well as scrutiny that could heighten all of the risks identified in this risk factor.

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, our customers and our respective industries and to the diversion of investment to other industries, which could have a negative impact on the price of our Class A 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 or their suppliers based on climate change-related concerns, which could affect our or our customers’ access to capital for potential growth projects. Moreover, to the extent ESG matters negatively impact our or the fossil fuel industry’s reputation, we may not be able to compete as effectively to recruit or retain employees, which may adversely affect our 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.

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. The potential for such security threats subjects our operations to increased risks that could have a material adverse effect on our business, financial condition and results of operations. For example, unauthorized access to our reserves information or other proprietary information could lead to data corruption, communication interruptions, or other disruptions to our operations. 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.

Item 1B. Unresolved Staff Comments.

None.

Item 1C. Cybersecurity.

We have implemented a cybersecurity program to assess, identify, and manage risks from cybersecurity threats that may result in material adverse effects on the confidentiality, integrity, and availability of our information systems.

Primary responsibility for our cybersecurity program rests with our Vice President of Information Technology, who has extensive cybersecurity and information technology knowledge and skills gained from over 30 years of work experience at the Company and elsewhere. The Vice President of Information Technology is responsible for implementing, monitoring and maintaining cybersecurity and data protection practices across our business and reports directly to our Chief Financial Officer. The Vice President of Information Technology at times attends meetings of the Board to report on any material developments and risk management practices.

The Vice President of Information Technology meets regularly with members of our information technology team, which includes a security architect whose responsibilities are dedicated solely to cybersecurity matters, a network engineer, and infrastructure director to discuss the risk management measures implemented by the Company to identify and mitigate data protection and cybersecurity risks. Our cybersecurity team also works with our Chief Legal Officer to oversee compliance with legal, regulatory and contractual security requirements.

Our cybersecurity processes include automated tools and technical safeguards managed and monitored by our cybersecurity team. We regularly conduct penetration and vulnerability testing and security audits. We also employ systems and processes designed to oversee, identify, and reduce the potential impact of a security incident at a third-party vendor, service provider or customer or otherwise implicating the third-party technology and systems we use. In addition to our internal cybersecurity capabilities, we also at times engage assessors, auditors, or other third parties to assist with the assessment, identification, and management of cybersecurity risks.

Our Board has delegated the primary responsibility to oversee cybersecurity matters to our Audit Committee, but retains overall oversight responsibility for cybersecurity matters. The Board and Audit Committee periodically review the measures implemented by the Company to identify and mitigate risks from cybersecurity threats. As part of such reviews, the Board and Audit Committee receive reports from members of our team responsible for overseeing the Company’s cybersecurity risk management, which may address a wide range of topics including recent developments, evolving standards, vulnerability assessments, third-party and independent reviews, the threat environment, technological trends and information security considerations arising with respect to the Company’s peers and third parties. The Audit Committee discusses with such members of our management team our information technology systems and procedures and will report to the Board on any

material cybersecurity risks identified. We have protocols by which certain cybersecurity incidents are escalated within the Company and, where appropriate, reported to the Board and Audit Committee in a timely manner.

We have adopted an Information Security Incident Response Policy that applies in the event of a cybersecurity threat or incident (the “ISIRP”) to provide a standardized framework for responding to security incidents. The ISIRP sets out a coordinated approach to investigating, containing, documenting and mitigating incidents, including reporting findings and keeping senior management and other key stakeholders informed and involved as appropriate. The ISIRP applies to all Company personnel (including third-party contractors, vendors and partners) that perform functions or services that require access to secure Company information, and to all devices and network services that are owned or managed by the Company. As an additional measure to facilitate our timely and comprehensive response to any security incident, we engage a third party vendor on retainer to assist in such incidents.

As detailed elsewhere herein, we also rely on information technology and third party vendors to support our operations, including our secure processing of personal, confidential, sensitive, proprietary and other types of information. Despite ongoing efforts to continue improvement of our and our vendors’ ability to protect against cyber incidents, we may not be able to protect all information systems, and such incidents may lead to reputational harm, revenue and client loss, legal actions, statutory penalties, among other consequences. Risks from cybersecurity threats, including as a result of any previous cybersecurity incidents, have not materially affected us, including our business strategy, results of operations or financial condition, and we do not believe that such risks are reasonably likely to have such an effect over the long term.

Item 2. Properties

Our Non-Mining Properties

We lease office space for our corporate headquarters located at 333 Shops Boulevard, Suite 301, Willow Park, Texas 76087. We currently own or lease the following additional principal properties:

Our Mining Properties

As of December 31, 2023, our mining properties included eight sites (Kermit, Lamesa, Monahans, San Antonio, Hat Creek, River Ridge, Sunny Point and Merryville), which span the Permian, Eagle Ford and Haynesville as illustrated in the map that follows. As of December 31, 2023, we did not have any individually material mining properties.

Summary Overview of Our Mining and Processing Facilities

The following table sets forth certain information about our mining properties required to be included in our mining operations as of December 31, 2023 pursuant to Item 1303(a) of Regulation S-K:

All of our mines are operated by our subsidiary, Alpine Silica, LLC. Aggregate annual production of frac sand from our mines for the fiscal years ended on December 31, 2023, 2022 and 2021 was approximately 10.8 million tons, 9.2 million tons and 7.8 million tons, respectively, which includes production data for periods prior to our acquisition of the respective sand mines and is based on information provided by prior operators.

Summary of Operations and Production Statistics

The following table summarizes, for each of our properties, our mining and processing operations and production (sales volume) for the prior three years ended December 31. Production data is included for periods prior to our acquisition of the respective sand mines and is based on information provided by prior operators and as included in technical report summaries related to such properties prepared by John T. Boyd.

Description of Mining and Processing Facilities

The following provides an overview of our mining and processing facilities:

Kermit Sand Mine, Winkler County, TX

We operate a sand mine and processing facility located in Winkler County, Texas, strategically located in the Permian that we refer to as our “Kermit Sand Mine.” The Kermit Sand Mine is a surface sand mine and a production stage property located approximately 14 miles north-northeast of Kermit, Texas and approximately 58 miles west-northwest of the Midland-Odessa, Texas metropolitan area. The Kermit Sand Mine produces 40/200-mesh frac sand, which we primarily process into 40/70-mesh and 70/200-mesh frac sand products. The Kermit Sand Mine sand deposit is loosely consolidated and overlain with a thin layer of overburden; characteristics which are amenable to the use of conventional surface mining techniques. Since the Kermit Sand Mine sand formation does not extend below the water table, the quarry is dry-mined using medium-sized earthmoving equipment. Our Kermit Sand Mine facility features a wet plant (with two 300-tph wash circuits) and dry plant (with two 200-tph drying and sorting circuits) that processes frac sand. Once the frac sand is appropriately processed, it is stored in one of eight storage silos until it is transported by truck to its destination. Additional onsite facilities include a scale house, office, shop, quality laboratory and onsite housing for up to 40 employees. Approximately 45 employees are located at the Kermit Sand Mine to facilitate the processing and storage of frac sand.

Our Kermit Sand Mine operates under five operating permits and complies with other state and federal regulations that do not require a specific permit. The Kermit Sand Mine operates under an Air Quality Permit, which is renewable in 2028. Other permits for the mine include an annual Aggregate Production Operation Registration, a Petroleum Storage Tank Registration, a Stormwater Multi-Sector General Permit, and a Public Water System/Supply Registration application that is pending. There are no formal state or federal reclamation plans or permits required for the operation.

The Kermit Sand Mine comprises approximately 1,271 acres of mineral and/or surface rights controlled by us. Mineral rights for the subject property are held by one of our wholly owned indirect subsidiaries through a combination of 641 acres owned in fee, and 630 acres of leased property. The leased property agreement, held between Alpine and Bruce and Barr Ltd., is valid until the year 2052 with a stipulated production start deadline of January 1, 2032, and a royalty rate of 2% of gross sales revenue.

Lamesa Sand Mine, Dawson County, TX

We operate a sand mine and processing facility located in Dawson and Gaines Counties, Texas, strategically located in the Permian Basin that we refer to as our “Lamesa Sand Mine.” Our Lamesa Sand Mine is a surface sand mine and a production stage property located approximately 55 miles north of Midland, Texas, 60 miles south of Lubbock, Texas, and 13 miles northwest of Lamesa, Texas. The Lamesa Sand Mine produces 40/200-mesh frac sand, which we primarily process into 40/70-mesh and 70/200-mesh frac sand products. The Lamesa Sand Mine sand deposit is loosely consolidated and overlain with a thin layer of overburden; characteristics which are amenable to the use of conventional surface mining techniques. Since the Lamesa Sand Mine sand formation does not extend below the water table, the quarry is dry-mined using medium-sized earthmoving equipment. Our Lamesa Sand Mine facility features a wet plant (with two 250-tph wash circuits) and dry plant (with two 200-tph drying and sorting circuits) that processes frac sand. Once the frac sand is appropriately processed and classified, it is stored in one of four storage silos until it is transported by truck to its destination. Additional onsite facilities include an office building, shipping office and shop that support the mining and processing activities, and onsite housing for up to 36 employees. Approximately 50 employees are located at the Lamesa Sand Mine to facilitate the processing and storage of frac sand.

Our Lamesa Sand Mine operates under five operating permits and complies with other state and federal regulations that do not require a specific permit. The Lamesa Sand Mine operates under an air quality Permit by Rule, which does not have an expiration date. Other permits for the mine include an annual Aggregate Production Operation Registration, a Stormwater Multi-Sector General Permit, an On-Site Sewage Facility, and a Public Water System application that is pending. There are no formal state or federal reclamation plans or permits required for the operation.

The Lamesa Sand Mine comprises approximately 6,700 acres of mineral and surface rights controlled by us. The property is owned in fee by one of our wholly owned indirect subsidiaries and there are no associated lease agreements or royalty payments.

Monahans Sand Mine, Ector, Ward and Winkler Counties, TX

We operate a sand mine and processing facility located in Ector, Ward and Winkler Counties, Texas, strategically located in the Permian Basin that we refer to as our “Monahans Sand Mine.” We acquired the Monahans Sand Mine in late July 2022. Our Monahans Sand Mine is a surface sand mine and production stage property located approximately 10 miles east of Monahans, Texas and approximately 30 miles west of the Midland-Odessa, Texas metropolitan area. The Monahans Sand Mine produces 40/140-mesh frac sand, which we primarily process into 40/70-mesh and 70/140-mesh frac sand products. The Monahans Sand Mine sand deposit is loosely consolidated and overlain with a thin layer of overburden; characteristics which are amenable to the use of conventional surface mining techniques. Since the Monahans Sand Mine sand formation does not extend below the water table, the quarry is dry-mined using medium-sized earthmoving equipment. Our Monahans Sand Mine facility features a wet plant (with three 250-tph wash circuits) and dry plant (with two 250-tph drying and sorting circuits) that processes frac sand. Once the frac sand is appropriately processed and classified, it is stored in one of eight storage silos until it is transported by truck to its destination. Additional onsite facilities include an office building, various control rooms, a shop/warehouse and a quality laboratory that support the mining and processing activities. Approximately 55 employees are located at the Monahans Sand Mine to facilitate the processing and storage of frac sand.

Our Monahans Sand Mine operates under four permits and complies with other state and federal regulations that do not require a specific permit. The Monahans Sand Mine operates under an Air Quality Permit, which is renewable in 2029. Other permits for the mine include an annual Aggregate Production Operation Registration, an Industrial Hazardous Waste Solid Waste Registration, and a Stormwater Multi- Sector General Permit. There are no formal state or federal reclamation plans or permits required for the operation.

The Monahans Sand Mine comprises approximately 2,723 acres of surface and subsurface (i.e., mineral) rights leased from Lazy R Ranch, LP and Nina Resources LP. The Monahans Sand Mine lease agreement includes a royalty payable to the lessors in an amount equal to the greater of $1.00 per ton or 4.0% of the selling price (less transportation costs) for finished frac sand products sold subject to a minimum annual royalty payment of $1.25 million.

San Antonio Sand Mine, Bexar County, TX

We operate a sand mine and processing facility located in Bexar County, Texas, strategically located in the Eagle Ford that we refer to as our “San Antonio Sand Mine.” We acquired the San Antonio Sand Mine in December 2022. Our San Antonio Sand Mine is a surface sand mine and production stage property located approximately 8 miles south of the I-410 Loop on the outskirts of San Antonio, Texas. The San Antonio Sand Mine produces 35/140-mesh frac sand, which we primarily process into 35/70-mesh and 70/140-mesh frac sand products. The San Antonio Sand Mine sand deposit is loosely consolidated and overlain with a thin layer of overburden; characteristics which are amenable to the use of conventional surface mining techniques. Since the San Antonio Sand Mine sand formation does not extend below the water table, the quarry is dry-mined using medium-sized earthmoving equipment. Our San Antonio Sand Mine facility features a wet plant (with one 500-tph wash circuit) and dry plant (with two 200-tph drying and sorting circuits) that processes frac sand. Once the frac sand is appropriately processed and classified, it is stored in one of five storage silos until it is transported by truck to its destination. Additionally, the San Antonio Sand Mine has more than six acres of wet sand storage. Additional onsite facilities include an office/control room and extensive conveyor systems that support intra-plant product movement. Approximately 60 employees are located at the San Antonio Sand Mine to facilitate the processing and storage of frac sand.

Our San Antonio Sand Mine operates under five permits and complies with other state and federal regulations that do not require a specific permit. The San Antonio Sand Mine operates under an air quality Permit by Rule, which does not have an expiration date, while we apply for an Air Quality Permit. Other permits for the mine include an Aggregate Production Operation Registration, an Industrial Hazardous Waste Solid Waste Registration, a Petroleum Storage Tank Registration and a Stormwater Multi-Sector General Permit. There are no formal state or federal reclamation plans or permits required for the operation.

The San Antonio Sand Mine comprises approximately 735 acres of surface and subsurface (i.e., mineral) rights controlled by us. The property is owned in fee by one of our wholly owned indirect subsidiaries and there are no associated lease agreements or royalty payments.

River Ridge Sand Mine, Lafayette and Miller Counties, AR

We operate a sand mine and processing facility located in Miller and Lafayette Counties, Arkansas, strategically located in the Haynesville that we refer to as our “River Ridge Sand Mine.” We acquired the River Ridge Sand Mine in February 2023. Our River Ridge Sand Mine is a dredging and processing operation located along the western bank of the Red River approximately 10 miles southwest of Bradley, Arkansas and approximately 30 miles southeast of Texarkana, Arkansas. The River Ridge Sand Mine produces 30/140-mesh frac sand, which we primarily process into 30/70-mesh and 70/140-mesh frac sand products. Since the River Ridge Sand Mine sand formation lies near or below the water table, or is otherwise submerged, the mining operation employs dredging as the primary sand extraction method. Our River Ridge Sand Mine facility features a wet plant (with one 1,000-tph wash circuit) and dry plant (with three 200-tph drying and sorting circuits) that processes frac sand. Once the frac sand is appropriately processed and classified, it is stored in one of six storage silos until it is transported by truck to its destination. Additional onsite facilities include an office complex that supports the mining and processing activities. Approximately 125 employees are located at the River Ridge Sand Mine to facilitate the processing and storage of frac sand.

Our River Ridge Sand Mine operates under five permits and complies with other state and federal regulations that do not require a specific permit. The River Ridge Sand Mine operates under a state of Arkansas Minor Source Air Permit, which does not have an expiration date. Other permits for the mine include Industrial Stormwater General Permit, Wastewater Discharge Permit, Section 404 Permit for dredging, and an Open-Cut Mining Permit. There are no formal state or federal reclamation plans or permits required for the operation.

The River Ridge Sand Mine comprises approximately 1,928 acres owned in fee by one of our wholly owned indirect subsidiaries.

Hat Creek Sand Mine, Bossier and Caddo Parishes, LA

We operate a sand mine and processing facility located in Bossier and Caddo Parishes, Louisiana, strategically located in the Haynesville that we refer to as our “Hat Creek Sand Mine.” We acquired the Hat Creek Sand Mine in February 2023. Our Hat Creek Sand Mine is a dredging and processing operation located approximately 5 miles north of Shreveport, Louisiana. The Hat Creek Sand Mine produces 30/140-mesh frac sand, which we process into various mesh-size frac sand products. Since the Hat Creek Sand Mine sand formation lies near or below the water table, or is otherwise submerged, the mining operation employs dredging as the primary sand extraction method. Our Hat Creek Sand Mine facility features a wet plant (with one 400-tph wash circuit) and dry plant (with one 150-tph and one 200-tph drying and sorting circuits) that processes frac sand. Once the frac sand is appropriately processed and classified, it is stored in one of five storage silos until it is transported by truck to its destination. Additional onsite facilities include an office complex that supports the mining and processing activities. Approximately 65 employees are located at the Hat Creek Sand Mine to facilitate the processing and storage of frac sand.

Our Hat Creek Sand Mine operates under five permits and complies with other state and federal regulations that do not require a specific permit. The Hat Creek Sand Mine operates under a state of Louisiana Minor Source Air Permit that expires in 2027. Other permits for the mine include Water Quality Certification — Sand Mining Operations, Water Quality Certification — Commercial Dredging, Section 404 Permit for dredging, and a General Permit for Discharges Related to Extraction, Mining or Dredging of Dirt, Sand, Gravel, Shell or Similar Materials. There are no formal state or federal reclamation plans or permits required for the operation.

The Hat Creek Sand Mine comprises approximately 706 acres of leased surface and mineral rights. All frac sand production from the Hat Creek Sand Mine is subject to a royalty payable to the lessors in an amount equal to the greater of $1.00 per ton or 2.5% of the selling price for finished frac sand products sold.

Sunny Point Sand Mine, Bossier and Caddo Parishes, LA

We operate a sand mine and processing facility located in Bossier and Caddo Parishes, Louisiana, strategically located in the Haynesville that we refer to as our “Sunny Point Sand Mine.” We acquired the Sunny Point Sand Mine in February 2023. Our Sunny Point Sand Mine is a dredging and processing operation located approximately 10 miles southeast of Shreveport, LA. The Sunny Point Sand Mine produces 30/200-mesh frac sand, which we process into various mesh-size frac sand products. Since the Sunny Point Sand Mine sand formation lies near or below the water table, or is otherwise submerged, the mining operation employs dredging as the primary sand extraction method. Our Sunny Point Sand Mine facility features a wet plant (with one 800-tph wash circuit) and dry plant (with two 400-tph drying and sorting circuits) that processes frac sand. Once the frac sand is appropriately processed and classified, it is stored in one of four storage silos until it is transported by truck to its destination. Additional onsite facilities include an office complex that supports the mining and processing activities. Approximately 80 employees are located at the Sunny Point Sand Mine to facilitate the processing and storage of frac sand.

Our Sunny Point Sand Mine operates under five permits and complies with other state and federal regulations that do not require a specific permit. The Sunny Point Sand Mine operates under a state of Louisiana Minor Source Air Permit that expires in 2032. Other permits for the mine include Water Quality Certification—Sand Mining Operations, Water Quality Certification—Commercial Dredging, Section 404/ Section 10 Permit for dredging, and a General Permit for Discharges Related to Extraction, Mining or Dredging of Dirt, Sand, Gravel, Shell or Similar Materials. There are no formal state or federal reclamation plans or permits required for the operation.

The Sunny Point Sand Mine comprises approximately 783 acres of leased surface and mineral rights. The property comprises two noncontiguous parcels. The processing plant and associated facilities are located on the west side of the Red River along Louisiana Highway 1. The dredging area comprises an oxbow lake located east of the Red River. Natural levees have cut off the oxbow lake from the main river channel upstream; however, the lake remains connected to the Red River on the downstream section. Dredged material is pumped through pipelines beneath the Red River. A pumping station lies on the western bank of the oxbow lake. All frac sand production from the Sunny Point Sand Mine is subject to a royalty payable to the lessors of $1.00 per ton sold.

Merryville Sand Mine, Beauregard Parish, LA

We operate a sand mine and processing facility located in Beauregard Parish, Louisiana, strategically located in the Haynesville that we refer to as our “Merryville Sand Mine.” We acquired the Merryville Sand Mine in February 2023. Our Merryville Sand Mine is a dredging and processing operation located approximately 7 miles north-northeast of Merryville, LA and 10 miles west of DeRidder, LA along the southern bank of the Bayou Anacoco. The Merryville Sand Mine produces 30/100-mesh frac sand, which we process into various mesh-size frac sand products. The Merryville Sand Mine sand deposit is loosely consolidated and overlain with a thin layer of overburden; characteristics which are amenable to the use of conventional surface mining techniques. Since the Merryville Sand Mine sand formation does not extend below the water table, the quarry is dry-mined using medium-sized earthmoving equipment. Our Merryville Sand Mine facility features a dry plant (with two 250-tph drying and sorting circuits) that processes frac sand. A wet plant is not required because of the particle size distribution of the mine frac sand. Once the frac sand is appropriately processed and classified, it is stored in one of three storage silos until it is transported by truck to its destination. Additional onsite facilities include an office complex that supports the mining and processing activities. Approximately 45 employees are located at the Merryville Sand Mine to facilitate the processing and storage of frac sand.

Our Merryville Sand Mine operates under two permits and complies with other state and federal regulations that do not require a specific permit. The Merryville Sand Mine operates under a state of Louisiana Minor Source Air Permit that expires in 2032 and also has a General Permit for Discharges Related to Extraction, Mining or Dredging of Dirt, Sand, Gravel, Shell or Similar Materials. There are no formal state or federal reclamation plans or permits required for the operation.

The Merryville Sand Mine comprises approximately 810 acres of leased surface and mineral rights. All frac sand production from the Merryville Sand Mine is subject to a royalty payable to the lessors of $1.00 per ton sold. The Merryville Sand Mine lease is in effect from September 1, 2021 to August 31, 2024 and includes an “option to purchase” providing us the opportunity to purchase the property during the initial lease term for $4.8 million with annually prorated credit for royalties paid

Summary of Reserves

Information concerning our mining properties and mineral reserves has been prepared in accordance with the requirements of Subpart 1300 of Regulation S-K (“Reg. S-K 1300”). The terms “mineral resources,” “mineral reserve,” “proven mineral reserve,” and “probable mineral reserve,” whether singular or plural, are defined and used in accordance with Reg. S-K 1300. Under Reg. S-K 1300, mineral resources may not be classified as “mineral reserves” unless the determination has been made by a qualified person that the mineral resources can be the basis of an economically viable project. The amount of finished frac sand produced as a percentage of the raw frac sand mined, which is referred to as the processing yield (or plant yield), is analogous to the “cut-off grade” of other mining operations. If the expected processing yield of the frac sand is too low, the costs of production will outweigh sales revenues and the deposit cannot be economically mined. The minimum economic processing yield for each our mines, based on three-year historic financial results, is well below the expected processing yield of such mine. Other limiting criteria, such as minimum mining thicknesses or maximum stripping ratios (the ratio of waste to sand excavated) are generally not considered in the estimation of frac sand resources.

Set forth in the table below are estimates of our frac sand mineral reserves as of December 31, 2023. The estimates of frac sand mineral reserves at our mining properties have been prepared by John T. Boyd, our independent mining engineers and geologists, and in accordance with Reg. S-K 1300.

(a) Mineral reserves are reported at a selling price of $29.29 per ton, representing the expected weighted-average sales price over the expected life of the reserves based on our historical operating results, our short-term budget forecasts, and John T. Boyd’s knowledge of frac sand markets. The mining recovery factor was estimated to be 95%, and the processing yield was estimated to be 82.1%. Overall product yield was estimated to be 78% after mining and processing losses. The minimum economic processing yield is approximately 44% based on the Kermit Sand Mine’s historical and forecasted economics.

(b) Mineral reserves are reported at a selling price of $24.55 per ton, representing the expected weighted-average sales price over the expected life of the reserves based on our historical operating results, our short-term budget forecasts, and John T. Boyd’s knowledge of frac sand markets. The mining recovery factor was estimated to be 95%, and the processing yield was estimated to be 81.6%. Overall product yield was estimated to be 77.5% after mining and processing losses. The minimum economic processing yield is approximately 48% based on the Lamesa Sand Mine’s historical and forecasted economics. We previously reported in our annual report on Form 10-K for the period ended December 31, 2022 proven reserves for the Lamesa Sand Mine of approximately 56.11 million tons. The increase in mineral reserves from 2022 to 2023 is attributable to (1) an increase of 2.31 million tons due to revisions to mine plans and/or associated modifying factors as determined by the Company and John T. Boyd and (2) a decrease of 0.92 million tons due to depletion through ordinary mining operations and inventory sales.

(c) Mineral reserves are reported at a selling price of $25.97 per ton, representing the expected weighted-average sales price over the expected life of the reserves based on our historical operating results, our short-term budget forecasts, and John T. Boyd’s knowledge of frac sand markets. The mining recovery factor was estimated to be 95%, and the processing yield was estimated to be 80.8%. Overall product yield was estimated to be 76.7% after mining and processing losses. The minimum economic processing yield is approximately 56% based on the Monahans Sand Mine’s historical and forecasted economics. We previously reported in our annual report on Form 10-K for the period ended December 31, 2022 probable reserves for the Monahans Sand Mine of approximately 98.61 million tons. The increase in mineral reserves from 2022 to 2023 is attributable to (1) an increase of 18.07 million tons due to revisions to mine plans and/or associated modifying factors as determined by the Company and John T. Boyd and (2) a decrease of 1.63 million tons due to depletion through ordinary mining operations and inventory sales.

(d) Mineral reserves are reported at a selling price of $32.44 per ton, representing the expected weighted-average sales price over the expected life of the reserves based on our historical operating results, our short-term budget forecasts, and John T. Boyd’s knowledge of frac sand markets. The mining recovery factor was estimated to be 95%, and the processing yield was estimated to be 60.4%. Overall product yield was estimated to be 57.4% after mining and processing losses. The minimum economic processing yield is approximately 41% based on the San Antonio Sand Mine’s historical and forecasted economics. We previously reported in our annual report on Form 10-K for the period ended December 31, 2022 proven reserves for the San Antonio Sand Mine of approximately 42.32 million tons. The decrease in mineral reserves from 2022 to 2023 is attributable to (1) a decrease of 18.70 million tons due to revisions to mine plans and/or associated modifying factors as determined by the Company and John T. Boyd and (2) a decrease of 1.16 million tons due to depletion through ordinary mining operations and inventory sales.

(e) Mineral reserves are reported at a selling price of $35.18 per ton, representing the expected weighted-average sales price over the expected life of the reserves based on our historical operating results, our short-term budget forecasts, and John T. Boyd’s knowledge of frac sand markets. The mining recovery factor was estimated to be 95%, and the processing yield was estimated to be 66.4%. Overall product yield was estimated to be 63.1% after mining and processing losses. The minimum economic processing yield is approximately 27.5% based on the River Ridge Sand Mine’s historical and forecasted economics.

(f) Mineral reserves are reported at a selling price of $26.52 per ton, representing the expected weighted-average sales price over the expected life of the reserves based on our historical operating results, our short-term budget forecasts, and John T. Boyd’s knowledge of frac sand markets. The mining recovery factor was estimated to be 95%, and the processing yield was estimated to be 66.6%. Overall product yield was estimated to be 63.3% after mining and processing losses. The minimum economic processing yield is approximately 36.8% based on the Hat Creek Sand Mine’s historical and forecasted economics.

(g) Mineral reserves are reported at a selling price of $39.53 per ton, representing the expected weighted-average sales price over the expected life of the reserves based on our historical operating results, our short-term budget forecasts, and John T. Boyd’s knowledge of frac sand markets. The mining recovery factor was estimated to be 95%, and the processing yield was estimated to be 78.9%. Overall product yield was estimated to be 75.0% after mining and processing losses. The minimum economic processing yield is approximately 30.7% based on the Sunny Point Sand Mine’s historical and forecasted economics.

(h) Mineral reserves are reported at a selling price of $25.90 per ton, representing the expected weighted-average sales price over the expected life of the reserves based on our historical operating results, our short-term budget forecasts, and John T. Boyd’s knowledge of frac sand markets. The mining recovery factor was estimated to be 95%, and the processing yield was estimated to be 71.2%. Overall product yield was estimated to be 67.7% after mining and processing losses. The minimum economic processing yield is approximately 39.1% based on the Merryville Sand Mine’s historical and forecasted economics.

Summary of Resources

There are no reportable mineral resources in addition to those converted to mineral reserves. Quantities of frac sand controlled by us within the defined boundaries of the mining properties set forth above which are not reported as mineral reserves are not considered to have potential economic viability; as such, they are not reportable as mineral resources.

Internal Controls

The quantity and nature of our mineral reserves are estimated by third-party engineers. John T. Boyd independently prepared an estimate of our mineral reserves as of December 31, 2023, and we intend to continue retaining third party engineers to prepare estimates of our mineral reserves on an annual basis. We provided John T. Boyd certain operating and financial information for each of our mines to assist them in opining as to the economic viability of our mineral reserves. John T. Boyd did not verify historic drill hole data by conducting independent drilling in areas already explored. It is customary in preparing frac 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 the foregoing information with us. Before acquiring new mineral reserves, we or third-party engineers such as John T. Boyd perform or review surveying, drill core analysis and other tests to confirm the quantity and quality of the acquired mineral reserves.

For all properties, resource and reserve estimates are based on our mine planning efforts. Mine planning decisions are determined and agreed upon by our management based on information prepared by our personnel and third-party consultants. Management adjusts forward-looking models by reference to historic mining results, including reviewing performance versus predicted levels of production, and if necessary, re-evaluating mining methodologies if production outcomes were not realized as predicted. Ongoing mining and processing, along with product quality validation pursuant to periodic drill core sampling and customer expectations, provides further evidence as to the homogeneity, continuity and characteristics of the mineral deposit.

Management also assesses risks inherent in mineral resource and reserve estimates. For a discussion of the risks inherent in our mineral resource and reserve estimates, please refer to “Risk Factors — Risks Related to Our Business — Inaccuracies in our estimates of frac sand 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.”

Item 3. Legal Proceedings.

Information with respect to this Item is incorporated herein by reference to “Note 13 – Commitments and Contingencies” included in “Item 8. Financial Statements and Supplementary Data” of this Annual Report.

Item 4. Mine Safety Disclosures.

The information concerning mine safety violations and other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95 to this Annual Report on Form 10-K.

PART II

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

Market Information

Our Class A Common Stock is currently quoted on Nasdaq under the symbol “ACDC.” There is no public market for our Class B Common Stock or our Series A Preferred Stock.

Holders of our Class A Common Stock

As of March 11, 2024, there were 58 holders of record of our Class A Common Stock. The number of record holders is based upon the actual number of holders registered on the books of the Company at such date and does not include holders of shares in “street name” or persons, partnerships, associations, corporations or other entities identified in security position listings maintained by depositories.

Dividend Policy

The Issuer does not presently anticipate declaring or paying any cash dividends to holders of the 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 the then-existing conditions, including our results of operations, financial condition, capital requirements, investment opportunities, 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 the Class A Common Stock.

Recent Sales of Unregistered Equity Securities

We had no sales of unregistered equity securities during the period covered by this Annual Report that were not previously reported in a Current Report on Form 8-K or a Quarterly Report on Form 10-Q.

Issuer Purchases of Equity Securities

During the quarter ended December 31, 2023, we did not repurchase any of our equity securities.

Item 6. [Reserved]

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

The following discussion and analysis of our financial condition and results of operations should be read together with our consolidated financial statements and related notes included within “Item 8. Financial Statements and Supplementary Data.” In addition to historical consolidated financial information, the following discussion contains forward-looking statements that reflect the Company’s plans, estimates, or beliefs. Actual results could differ materially from those discussed in the forward-looking statements. Factors that could cause or contribute to these differences include those discussed below and elsewhere in this Annual Report, including, without limitation, those described in the sections titled “Cautionary Note Regarding Forward-Looking Statements” and Part I, Item 1A “Risk Factors.”

Overview

We are a vertically integrated and innovation-driven energy services holding company providing hydraulic fracturing, proppant production, other completion services and other complementary products and services to leading upstream oil and natural gas companies engaged in the exploration and production ("E&P") of North American unconventional oil and natural gas resources.

We operate in three reportable business segments: stimulation services, proppant production and manufacturing. Our stimulation services segment owns and operates a fleet of mobile hydraulic fracturing units and other auxiliary equipment that generates revenue by providing stimulation services to our customers. Our proppant production segment provides proppant to oilfield service providers and E&P companies. Our manufacturing segment sells highly engineered, tight tolerance machined, assembled, and factory tested products such as high horsepower pumps, valves, piping, swivels, large-bore manifold systems, and fluid ends.

Before our corporate reorganization on May 17, 2022, our consolidated financial statements presented herein consisted of the accounts of our predecessor as discussed below. Subsequent to May 17, 2022, our consolidated financial statements presented herein include our accounts and those of our subsidiaries that are wholly-owned, controlled by us, or a VIE where we are the primary beneficiary.

Our Predecessor and ProFrac Holding Corp.

Our predecessor consists of ProFrac LLC and its subsidiaries, Best Pump & Flow LP (“Best Flow”) and Alpine Silica, LLC (“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 of the Wilks Parties. 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 Annual Report 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.

Summary Financial Results

2023 Significant Events

In December 2023, we completed the refinancing of our existing senior secured term loan and other debt with two new financings totaling $885 million, which will both mature in 2029. As a result of these transactions, we extended our significant debt maturities to 2029, and obtained the financial flexibility to take advantage of the expected increase in activity levels in 2024. For more information, see “Note 6 – Debt” in the notes to our consolidated financial statements.

In September 2023, we entered into a purchase agreement with THRC Holdings, LP and FARJO Holdings, LP, both Wilks Parties, whereby we issued and sold 50,000 shares of Preferred Stock for gross proceeds of $50.0 million. For more information, see “Note 8 – Preferred Stock” and “Note 16 – Related Party Transactions” in the notes to our consolidated financial statements.

In February 2023, we acquired Performance Proppants, LLC, a Texas limited liability company, and certain related companies for total purchase consideration of approximately $462.8 million. Performance Proppants is a frac sand provider with four sand mines in the Haynesville basin.

In January 2023, we acquired Producers Service Holdings LLC, a Delaware limited liability company, an employee-owned pressure pumping services provider serving Appalachia and the Mid-Continent, for total purchase consideration of approximately $35.0 million. Through this transaction, we added hydraulic fracturing equipment, totaling 200,000 HHP as

well as a 50,000 square foot manufacturing facility located near Zanesville, OH, through which we have expanded our manufacturing footprint to support Northeast operations.

2022 Significant Events

In the second quarter of 2022, we completed an IPO of 18.2 million shares of its Class A common stock, par value $0.01 per share at a public offering price of $18.00 per share, which generated combined net proceeds of $301.7 million, after deducting underwriter discounts and commissions and estimated offering costs.

On March 4, 2022, we acquired FTS International, Inc. for total purchase consideration of approximately $405.7 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 operated in the Permian Basin, Eagle Ford Shale, Midcontinent, Haynesville Shale and Uinta Basin.

Through a series of transactions in the first half of 2022, we entered into a supply agreement with Flotek Industries, Inc. (“Flotek”) to provide full downhole chemistry solutions for 30 of our hydraulic fracturing fleets for a period of ten years starting on April 1, 2022. In connection with this transaction, we determined that Flotek was a variable interest entity and that we were the primary beneficiary. As a result, subsequent to May 17, 2022, the date that Flotek shareholders approved the supply agreement, we have included Flotek in our consolidated financial statements.

On July 25, 2022, we acquired the West Texas subsidiaries of Signal Peak Silica, for total purchase consideration of approximately $97.4 million. This acquisition expanded our in-basin frac sand mining operations in the Permian Basin.

In November 2022, we acquired U.S. Well Services, Inc. (“USWS”) for total purchase consideration of approximately $479.1 million. USWS was a technology-driven oilfield service company focused on electric-powered pressure pumping services in the United States. The USWS fleets consisted mostly of all-electric hydraulic fracturing equipment. The USWS electric fleets replace the engines, transmissions, and radiators used in conventional diesel fleets with electric motors.

In December 2022, we completed the acquisition of the Eagle Ford sand mining operations of Monarch Silica, LLC, for total purchase consideration of approximately $166.5 million. This acquisition added the Eagle Ford Shale to our in-basin frac sand mining operations.

In December 2022, we acquired REV Energy Holdings, LLC (“REV”), for total purchase consideration of approximately $140.6 million. REV was a hydraulic fracturing service provider with 204,500 HHP. REV operated in the Rocky Mountains and Eagle Ford Shale.

See Note 4 – Business Combinations” and “Note 16 – Related Party Transactions” in the notes to our consolidated financial statements for additional discussion related to our acquisitions.

Overall Trends and Outlook

Our customers’ focus on capital discipline and shareholder returns has reduced volatility in the rig count, which has reduced the volatility of demand for our services relative to historical trends. This has allowed us to maintain activity levels and pricing levels that contribute to an attractive return on our assets. We believe the industry’s activity levels will be maintained during 2024 allowing for continued cash flow generation. Our entire organization is focused on improving our performance in 2024 through three areas of focus: providing superior customer service, improved utilization of our assets, and continuously reducing our cost per unit. We expect these areas of focus, combined with our strategic initiatives, to improve our relative commercial positioning and financial results during 2024.

Results of Operations

Revenues

The following table summarizes revenues by reportable segment:

Stimulation services revenues in 2023 decreased $57.5 million, or 2%, from 2022. This decrease was due to a decrease in average active fleets and lower fleet utilization in 2023. These decreases were substantially offset by the full year effect of our acquisitions when compared with last year. Stimulation services revenues in 2022 increased $1,603.3 million, or 215%, from 2021. This increase was due to an increase in customer activity and an increase in active fleets, pumping hours and pricing in 2022. FTSI and USWS contributed revenue to this segment from their acquisition dates in 2022.

Proppant production revenues in 2023 increased $293.3 million, or 326%, from 2022. This increase was due to our acquisitions which increased the number of mines operated and the related tonnage mined. Revenue recognized for the amortization of acquired off-market contracts was $57.5 million and $6.6 million in 2023 and 2022, respectively. Proppant production revenues in 2022 increased $62.8 million, or 231%, from 2021. This increase was due to an increase in proppant volumes and pricing resulting from increased proppant demand primarily in the Permian basin. Additionally, Monahans contributed revenue to this segment from its acquisition date. Intersegment revenues for the proppant production segment were 30%, 62% and 40%, in 2023, 2022, and 2021, respectively.

Manufacturing revenues in 2023 increased $9.4 million, or 6%, from 2022. This increase was primarily attributable to increased activity in our stimulation services segment. Manufacturing revenues in 2022 increased $90.3 million, or 118%, from 2021. This increase was primarily attributable to increased activity in our stimulation services segment. Intersegment revenues for the manufacturing segment were 89%, 92% and 90%, in 2023, 2022, and 2021, respectively.

Other revenues in 2023 increased $81.2 million, or 73%, from 2022. This increase was due to Flotek’s increased revenues from the supply contract with our stimulation services segment. Flotek recorded $20.1 million of revenue related to contract shortfalls because the stimulation services segment did not purchase the minimum contractual commitment of chemistry products from Flotek. Intersegment revenues for Flotek were 65% and 67%, in 2023 and 2022, respectively. Flotek was acquired in 2022 and therefore contributed no revenues in 2021.

Cost of Revenues

The following table summarizes our cost of revenues by reportable segment:

Stimulation services cost of revenues in 2023 increased $202.9 million, or 14%, from 2022. This increase was due to the full year effect of our acquisitions when compared with last year and was partially offset by our decrease in average active fleets in 2023. Cost of revenues for this segment included an intercompany supply commitment charge of $20.1 million because the stimulation services segment did not purchase the minimum contractual commitment of chemistry products from Flotek. Stimulation services cost of revenues in 2022 increased $862.8 million, or 151%, from 2021. This increase was due to an increase in customer activity levels and increased prices for proppant and chemicals used in the fracturing process. Additionally, FTSI and USWS contributed costs to this segment from their acquisition dates.

Proppant production cost of revenues in 2023 increased $128.9 million, or 318%, from 2022. This increase was due to acquisitions which increased the number of mines operated and the related tonnage mined. Proppant production cost of revenues in 2022 increased $26.4 million, or 187%, from 2021. This increase was due to an increase in proppant production to meet increased customer demand in 2022. Additionally, Monahans contributed costs to this segment from its acquisition date.

Manufacturing cost of revenues in 2023 increased $9.1 million, or 7%, from 2022. This increase was due to increased activity in our stimulation services segment in 2023. Manufacturing cost of revenues in 2022 increased $71.7 million, or 109%, from 2021. This increase was due to increased activity in our stimulation services segment as well as higher prices for the cost of raw materials in 2022.

Other cost of revenues in 2023 increased $47.8 million, or 40%, from 2022. This increase was due to Flotek’s increased volumes from performing under the supply contract with our stimulation services segment. Flotek was acquired in 2022 and therefore contributed no cost of revenues in 2021.

Selling, General and Administrative

The following table summarizes our selling, general and administrative expenses:

Selling, general and administrative (“SG&A”) expenses in 2023 increased $25.4 million, or 10%, from 2022. Excluding stock-based compensation expense, SG&A expenses increased $63.0 million, or 36%. This increase was due to higher labor and non-labor costs associated with our acquisitions. Subsequent to June 30, 2023, we adjusted our cost structure to right size our organization, through the acceleration of acquisition synergies and headcount reductions. In the fourth quarter of 2023, our SG&A expenses, excluding stock-based compensation, decreased 5% from the same period last year.

SG&A expenses in 2022 increased $178.9 million, or 279%, from 2021. Excluding stock-based compensation expense, SG&A expenses increased $111.5 million, or 174%. This increase was due to increased headcount, incentive compensation and non-labor costs in 2022 associated with our increased activity levels and 2022 acquisitions. In 2022 we also recognized stock-based compensation associated with certain deemed shareholder contributions. See “Note 10 – Stock-based Compensation” in the notes to our consolidated financial statements for discussion of our stock-based compensation related to deemed contributions.

Depreciation, Depletion, and Amortization

The following table summarizes our depreciation, depletion, and amortization:

Depreciation, depletion, and amortization in 2023 increased $171.1 million, or 64%, from 2022. This increase was due to increased depreciation in 2023 from our acquisitions and increased capital expenditures in recent periods as well as increased amortization from customer relationship intangible assets acquired in 2023. The increase in depletion was due to our acquired sand mines. Depreciation, depletion, and amortization in 2022 increased $126.6 million, or 90%, from 2021. This increase was due to increased depreciation in 2022 from increased capital expenditure in 2022 and the depreciation related to the assets acquired from FTSI and USWS acquisition in 2022.

Acquisition Related Expenses

Acquisition and integration costs consist of professional and advisory fees, acquisition related severance expenditures, and other costs associated with acquisition and integration activities. Acquisition related expenses were $21.8 million, $48.8 million and zero in 2023, 2022 and 2021, respectively. These costs related to our acquisition and integration activities in 2023 and 2022. We expect for these expenses to significantly decrease in 2024 due to reduced acquisition and integration related activities.

Other Operating Expenses, Net

The following table summarizes our other operating expenses, net:

Loss on disposal of assets, net consists of gains or losses on excess property, early equipment failures, and other asset dispositions.

Litigation expenses and accruals for legal contingencies generally represent legal and professional fees incurred in litigation as well as estimates for loss contingencies with regards to certain vendor disputes and litigation matters. In 2023 more than half of these costs are related to litigation costs incurred in connection with multiple patent infringement lawsuits against Halliburton. See “Note 13 - Commitments and Contingencies” in the notes to our consolidated financial statements for further discussion.

Severance charges in 2023 related to the departure of two executives.

Impairments of long-lived assets in 2023 related to certain construction-in-process assets at one of our acquired sand mines that were abandoned.

The acquisition earnout adjustments represent a decrease in the fair value of the contingent consideration related to our acquisition of REV in December 2022.

Interest Expense, Net

Interest expense, net in 2023 increased by $95.4 million from 2022. This increase was primarily due to a higher average debt balance in 2023 and higher average interest rates in 2023. Interest expense, net in 2022 increased by $33.7 million from 2021. This increase was primarily due to a higher average debt balance in 2022 and higher average interest rates in 2022. We are subject to interest rate risk on our variable-rate debt. A 1% increase in interest rates on our variable-rate debt as of December 31, 2023, would increase the annual interest expense for this debt by approximately $10.0 million. See “Note 6 – Debt” in the notes to our consolidated financial statements for additional discussion related to our debt.

Loss on Extinguishment of Debt

As a result of debt refinancing transactions and debt repayments in 2023, we recognized a loss on extinguishment of debt in 2023 of $33.5 million compared with $17.6 million and $0.5 million in 2022 and 2021, respectively.

Other Income (Expense), Net

Other expense, net in 2023 was $36.2 million. This balance was primarily due to an unrealized loss on our investment in BPC of $30.2 million. See “Note 5 - Investments” in the notes to our consolidated financial statements for discussion of our investment in BPC. This balance was also due to and a loss of $8.5 million on our Munger make-whole provision. See “Note 14 - Fair Value Measurements” in the notes to our consolidated financial statements for discussion of the Munger make-whole provision.

Other income, net in 2022 was $16.5 million. This balance included a gain of $10.2 million related to the change in fair value of the Flotek Convertible Notes before we obtained control of Flotek. This balance also contained an unrealized gain of $4.2 million on the Munger make-whole provision.

Income Tax Benefit (Expense)

Income tax expense in 2023 was $1.2 million for an effective tax rate of negative 2.1%. The difference between the U.S. statutory tax rate of 21% and the effective tax rate was due to the income that was earned within the financial statement consolidated group that was not subject to tax within the financial statement consolidated group and changes in the valuation allowance on our net deferred tax assets.

Income tax expense in 2022 was $9.1 million for an effective tax rate of 2.6%. The difference between the U.S. statutory tax rate of 21% and the effective tax rate was due to the income that was earned within the financial statement consolidated group that was not subject to tax within the financial statement consolidated group after the Company’s corporate reorganization to a taxable entity subsequent to the IPO and changes in the valuation allowance on our net deferred tax assets.

Income tax benefit in 2021 was $0.2 million. The difference between the U.S. statutory tax rate of 21% and the effective tax rate was due to the Company’s partnership tax status in 2021.

Liquidity and Capital Resources

Sources of Liquidity

Historically, our primary sources of liquidity have been borrowings under our debt agreements and cash flows from operations. In 2023, the Company raised $50.0 million from the sale of its Series A preferred stock to THRC Holdings and FARJO Holdings. The Company presently does not expect any further funds from this source. THRC Holdings and FARJO Holdings are Wilks Parties. See “Note 16 – Related Party Transactions” in the notes to our consolidated financial statements.

While Flotek is included in our consolidated financial statements, we do not have the ability to access or use Flotek’s cash or liquidity in our operations and, accordingly, have excluded Flotek’s cash and other sources of liquidity from the following discussion of our liquidity and capital resources. See “Note 4 – Business Combinations” in the notes to our consolidated financial statements for discussion of our ownership of Flotek.

Our Alpine 2023 Term Loan requires us to segregate collateral associated with Alpine and limits our ability to use Alpine's cash or assets to satisfy our obligations or the obligations of our other subsidiaries. We also have limited ability to provide Alpine with liquidity to satisfy its obligations. See “Note 6 – Debt” in the notes to our consolidated financial statements for more information.

At December 31, 2023, we had $19.3 million of cash and cash equivalents, excluding Flotek, and $83.4 million available for borrowings under our revolving credit facility which resulted in a total liquidity position of $102.7 million. Refer to “Note 6 – Debt” in the notes to our consolidated financial statements for more information regarding our revolving credit facility.

We believe that our cash and cash equivalents, cash provided by operations, and the availability under our revolving credit facility will be sufficient to fund our capital expenditures, satisfy our obligations, and remain in compliance with our existing debt covenants for at least the next 12 months. If we pursue additional acquisitions during 2024 we will likely need to raise additional debt and/or equity financing to fund them. There is no assurance we could do that on favorable terms, if at all.

Flotek Liquidity

In Flotek’s Form 10-Q filed on November 8, 2023, Flotek concluded that there was substantial doubt about its ability to continue as a going concern due to limited sources of liquidity. Flotek is evaluating strategies to obtain additional funding to improve its liquidity position and believes it will be able to continue to fund its operations. We believe that substantial doubt about Flotek’s ability to continue as a going concern does not materially adversely affect our business, financial condition or results of operations as we do not guarantee any Flotek liabilities and we have access to other chemical suppliers.

Cash Flows

The following table provides a summary of our cash flows:

Net cash provided by operating activities was $553.5 million, $415.2 million, and $43.9 million in 2023, 2022 and 2021, respectively. Cash flows from operating activities consists of net income or loss adjusted for non-cash items and changes in operating assets and liabilities.

Net income or loss adjusted for non-cash items in 2023 resulted in a cash increase of $423.5 million compared with a cash increase of $679.5 million in 2022 and a cash increase of $108.4 million in 2021. The change from 2022 to 2023 was primarily due to lower earnings in 2023. The change from 2021 to 2022 was primarily due to higher earnings in 2022.

The net change in operating assets and liabilities in 2023 resulted in a cash increase of $130.0 million compared with a cash decrease of $264.3 million in 2022 and a cash decrease of $64.5 million in 2021. The change from 2022 to 2023 was primarily due to an increase in cash provided by accounts receivable in 2023, when compared with 2022, resulting from our decreased activity levels and lower working capital needs in 2023. The change from 2021 to 2022 was primarily due to increased working capital needs to fund our increased activity levels in 2022.

Net cash used in investing activities was $715.8 million, $1,028.6 million and $78.4 million in 2023, 2022 and 2021, respectively. The change from 2022 to 2023 was primarily due to decreased cash used for acquisitions, capital expenditures

and other investments. The change from 2021 to 2022 was primarily due to $640.7 in net cash paid for acquisitions and higher capital expenditures of $268.8 million related to dual fuel engine upgrades, engine standby controller installations, and our electric frac fleet build program. These uses of cash were partially offset by cash proceeds from a sale-leaseback of real property.

Net cash provided by financing activities was $149.7 million, $645.9 million, and $36.9 million in 2023, 2022, and 2021, respectively. In 2023 cash borrowed net of debt repayments was $101.6 million and we received $48.9 million in net proceeds from our preferred stock offering. In 2022 cash borrowed net of debt repayments was $413.8 million and we also received $228.8 million of proceeds from our IPO and related transactions. In 2021 cash borrowed net of debt repayments was $39.4 million.

Cash Requirements

Our material cash requirements have consisted of, and we anticipate will continue to consist of the following:

Debt Service Obligations

The following table summarizes our outstanding indebtedness as of December 31, 2023 and our future maturities:

See “Note 6 – Debt” and “Note 7 - Leases” in the notes to our consolidated financial statements for the discussion of our various debt agreements and capital leases, respectively.

Capital Expenditures

The nature of our capital expenditures consists of a base level of investment required to support our current operations and amounts related to growth and company initiatives.

In 2023 our capital expenditures were $267.0 million, consisting of maintenance capital expenditures for our fleet, building four electric-powered hydraulic fracturing fleets, and engine upgrades to convert legacy pumps to next generation technology. During the second quarter of 2023, we decided to reduce capital expenditures for the remainder of the year to more closely align with our customers’ activity levels and our reduced number of active fleets as well as to maintain target return thresholds on capital investments.

In 2024 we estimate capital expenditures will range from $150 million to $200 million in maintenance related expenditures and an additional $100.0 million for growth initiatives across all segments. Currently, growth capital expenditures for 2024 are expected to be related to sand mine improvements and upgrades to our hydraulic fracturing fleet.

We continually evaluate our capital expenditures and the amount that we ultimately spend will depend on a number of factors, including customer demand for fleets and expected industry activity levels. We believe we will be able to fund our 2024 capital program from cash flows from operations.

Purchase Commitments

As of December 31, 2023, we had purchase commitments of $29.8 million in 2024 for hydraulic fracturing equipment components.

Tax Receivable Agreement

In connection with our initial public offering, ProFrac Corp. entered into a tax receivable agreement (the “TRA”) with certain holders of limited liability company interests in ProFrac LLC (the “TRA Holders”). The TRA generally provides for payment by ProFrac 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 that ProFrac Corp. actually realizes as a result of certain equity transactions performed by the TRA Holders.

In 2023 the TRA Holders converted all of their Class B common stock to Class A common stock. See “Note 1 – Organization and Description of Business” in the notes to our consolidated financial statements for further discussion of this common stock conversion and related transactions. The tax effect of our IPO and this transaction resulted in an estimated $68.1 million noncurrent TRA liability. As of December 31, 2023, the current liability for our TRA obligation was an additional $2.8 million. The TRA liability will generally be paid under the TRA as ProFrac Corp. realizes actual cash tax savings from the

tax benefits covered by the TRA in future tax years. We do not expect a significant increase in the estimate of this liability in future periods.

Commitments and Contingencies

We are currently litigating multiple patent infringement lawsuits against Halliburton. The outcomes of these cases are uncertain and the ultimate resolution of them could have a material adverse effect on our liquidity in the periods in which these matters are resolved. See “Note 13 - Commitments and Contingencies” in the notes to our consolidated financial statements for further discussion.

Critical Accounting Policies and Estimates

The preparation of our consolidated financial statements and related notes requires us to make estimates that affect the reported amounts of assets, liabilities, revenue and expenses, and related disclosures of contingent assets and liabilities. We base these estimates on historical results and various other assumptions believed to be reasonable, all of which form the basis for making estimates concerning the carrying values of assets and liabilities that are not readily available from other sources. Actual results may differ from these estimates, and such differences could be material.

In the notes accompanying the consolidated financial statements included elsewhere in this annual report, we describe the significant accounting policies used in the preparation of our consolidated financial statements. We believe that the following represent the most significant estimates and management judgments used in preparing the consolidated financial statements.

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.

Goodwill

Goodwill is evaluated for impairment annually in the fourth quarter or whenever events or circumstances indicate the carrying value may not be recoverable. The impairment test involves a comparison of the fair value of each reporting unit with its carrying value. Fair value reflects our estimate of the price a potential market participant would be willing to pay for the reporting unit in an arms-length transaction. Reporting units with significant goodwill balances at December 31, 2023, include our Stimulation Services reporting unit, Flotek reporting unit, and our Haynesville Proppant Production reporting unit, which represents our Performance Proppants acquisition.

Determining the fair value of a reporting unit requires complex analysis and judgment. We use a combination of discounted cash flow models and market data, such as earnings multiples and quoted market prices, for observable comparable companies. Discounted cash flow models require detailed forecasts of cash flow drivers, such as revenue growth rates, margin rates, and capital investments as well as estimates of weighted-average cost of capital rates. These estimates are made in the context of many uncertain factors, such as the effectiveness of our strategy, changes in customer behavior, technological changes, competitor actions, regulatory changes and macroeconomic trends.

Due to the decrease in our consolidated financial results and the decrease in our market capitalization in 2023, we elected to test the goodwill for our Stimulation Services reporting unit and our Haynesville Proppant Production reporting unit using a quantitative impairment assessment, which required us to estimate the fair values of these reporting units.

Based on our quantitative and qualitative assessments, we determined that none of the goodwill for our reporting units was impaired at December 31, 2023. The excess fair value as a percentage of book value for our Stimulation Services reporting

unit was more than 20%. The fair value of our Haynesville Proppant Production reporting unit was marginally in excess of its book value at December 31, 2023, which we concluded was reasonable considering that the acquisition of Performance Proppants was nine months before the measurement date. When estimating the future cash flows for these reporting units, we generally assumed revenue and operating margins in future years would increase as we implement new commercial strategies for these reporting units and increase the utilization of our assets. However, if overall market conditions deteriorate, or if we are unable to achieve our forecasted results, future non-cash impairment charges may result which could be material. The fair value of our Flotek reporting unit was marginally in excess of its book value at December 31, 2023. The fair value for the Flotek reporting unit is derived from the observable trading price of its publicly-traded common stock. If the price of Flotek’s common stock has a sustained decline, a future non-cash impairment charge may result which could be material.

Income Taxes

Before May 17, 2022, the ProFrac Predecessor entities were organized as limited liability companies or a limited partnership and were treated as either a disregarded entity or a partnership for U.S. federal income tax purposes, whereby the ordinary business income or loss and certain deductions were passed-through and reported on the members’ income tax returns. As such, the Company was not required to account for U.S. federal income taxes in the consolidated financial statements. Certain state income-based taxes are imposed on the Company which are reflected as income tax expense or benefit in historical periods.

In connection with the IPO in May 2022, the Company reorganized and ProFrac LLC became partially owned by ProFrac Corp., a U.S. Internal Revenue Code Subchapter C corporation (“C-Corporation”). ProFrac Corp. is a taxable entity and is required to account for income taxes under the asset and liability method for periods subsequent to May 17, 2022.

Income taxes are accounted for using the asset and liability method. Deferred taxes are recognized for the tax consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities. We recognize future tax benefits to the extent that such benefits are more likely than not to be realized.

We record a valuation allowance to reduce the value of a deferred tax asset if based on the consideration of all available evidence, it is more likely than not that all or some portion of the deferred tax asset will not be realized. Significant weight is given to evidence that can be objectively verified. We evaluate our deferred income taxes at each reporting date to determine if a valuation allowance is required by considering all available evidence, including historical and projected taxable income and tax planning strategies. We will adjust a previously established valuation allowance if we change our assessment of the amount of deferred income tax asset that is more likely than not to be realized.

An estimate of whether a valuation allowance is necessary and the related amount of the valuation allowance contain uncertainties because it requires us to apply judgment to all positive and negative evidence available to us. When considering the likelihood of whether a deferred tax asset will be available to offset future taxable income, we assess, among other things, our historical and projected income or loss. When performing this assessment, we must consider the cyclical nature of our business. Our business is heavily influenced by current and expected prices for oil and natural gas. These prices are outside of our control and a downturn in the market can result in periods of significant losses for us, which could prevent the realization of a deferred tax asset. We therefore must consider the future possibility of an industry downturn and the severity of its effect on our business when considering all positive and negative evidence related to the realization of our deferred tax assets. Although we believe that our judgments and estimates are reasonable, an adjustment to a valuation allowance in a given period may require a material adjustment in a future period if our assumptions regarding our future taxable income are proven inaccurate due to an industry downturn.

We record uncertain tax positions, if any, in accordance with ASC 740 on the basis of a two-step process in which (1) we determine whether it is more likely than not that the tax positions will be sustained on the basis of the technical merits of the position and (2) for those tax positions that meet the more-likely-than-not recognition threshold, we recognize the largest amount of tax benefit that is more than 50 percent likely to be realized upon ultimate settlement with the related tax authority. We had no uncertain tax positions during the periods presented.

Property, Plant and Equipment

We calculate depreciation based on the estimated useful lives of our assets. When assets are placed into service, we make estimates with respect to their useful lives that we believe are reasonable. However, the cyclical nature of our business, which results in fluctuations in the use of our equipment and the environments in which we operate, could cause us to change our estimates, thus affecting the future calculation of depreciation.

We continuously perform repair and maintenance expenditures on our service and mining equipment. Expenditures for renewals and betterments that extend the lives of our equipment, which may include the replacement of significant components of equipment, are capitalized and depreciated. Other repairs and maintenance costs are expensed as incurred. The

determination of whether an expenditure should be capitalized or expensed requires management judgment with regard to the effect of the expenditure on the useful life of the equipment.

We separately identify and account for certain significant components of our hydraulic fracturing units including the engine, transmission, and pump, which requires us to separately estimate the useful lives of these components.

Recent Accounting Pronouncements

See “Note 2 – Summary of Significant Accounting Policies” in the notes to our consolidated financial statements for further discussion regarding recently issued accounting standards.

Related Party Transactions

See “Note 16 – Related Party Transactions” in the notes to our consolidated financial statements for further discussion regarding related party transactions.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

At December 31, 2023, we held no derivative instruments that materially increased our exposure to market risks for interest rates, foreign currency rates, commodity prices or other market price risks.

We are subject to interest rate risk on our variable-rate debt. A 1% increase in interest rates on our variable-rate debt as of December 31, 2023, would increase the annual interest payments for this debt by approximately $10.0 million.

Item 8. Financial Statements and Supplementary Data

INDEX TO FINANCIAL STATEMENTS

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

ProFrac Holding Corp.

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of ProFrac Holding Corp. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2023 and 2022, the related consolidated statements of operations, comprehensive income (loss), changes in equity, and cash flows for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the “financial statements”). In our opinion, based on our audits and the report of the other auditors, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2023, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated March 15, 2024 expressed an unqualified opinion.

We did not audit the financial statements of Flotek Industries, Inc., a consolidated variable interest entity as of and for the period ended December 31, 2022, which statements reflect total assets constituting 3% of consolidated total assets as of December 31, 2022, and total revenues of 2% of consolidated total revenues for the year then ended. Those statements were audited by other auditors, whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Flotek Industries, Inc., is based solely on the report of the other auditors.

Basis for opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical audit matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Estimation of fair value of certain acquired assets and liabilities

As described further in Note 4 to the financial statements, the Company acquired 100% of the issued and outstanding membership interests in (i) Performance Proppants, LLC, (ii) Red River Land Holdings, LLC, (iii) Performance Royalty, LLC, (iv) Performance Proppants International, LLC, and (v) Sunny Point Aggregates, LLC (together, “Performance Proppants”) for a total purchase consideration of $462.8 million. We identified the estimation of fair value of certain acquired assets and liabilities of Performance Proppants as a critical audit matter.

The principal considerations for our determination that the estimation of fair value of the acquired assets and liabilities of Performance Proppants is a critical audit matter are that the methods used to determine fair value, including the application of significant inputs and assumptions within the determination of fair value, require management to make significant judgments regarding the anticipated future results of the acquired business and to select inputs and assumptions that are relevant and supportable for the acquisition. The Company utilized valuation specialists to assist in developing the estimates of fair value

of acquired assets and liabilities. The presence of management judgment, including the selection of significant inputs and assumptions, and the use of valuation specialists, caused the audit procedures associated with the estimation of fair value of certain acquired assets and liabilities to be especially challenging and to require the use of auditor judgment in determining the extent of audit effort, including the need to involve professionals having expertise in the valuation of acquired assets and liabilities.

Our audit procedures related to the estimation of fair value of certain acquired assets and liabilities of Performance Proppants included the following, among others.

Goodwill recoverability testing for the Stimulation Services and Haynesville Proppant Production reporting units

As described further in note 2 to the financial statements, the Company has $169.7 million of goodwill related to its Stimulation Services reporting unit and $74.5 million of goodwill related to its Proppant Production reportable segment, of which $67.7 million related to the Haynesville Proppant Production reporting unit. Goodwill is required to be tested annually, and for the Stimulation Services and Haynesville Proppant Production reporting units, management determined that a quantitative impairment test was necessary in the fourth quarter of 2023. The estimation of fair value of a reporting unit in connection with a quantitative impairment test requires management to make estimates and judgments regarding future operating results. We identified the estimation of fair value of the aforementioned reporting units as a critical audit matter.

The principal considerations for our determination that the estimation of fair value of each of the reporting units is a critical audit matter are that the methods used to determine fair value, including the application of significant inputs and assumptions within the determination of fair value, require management to make significant judgments regarding the anticipated future results of the reporting units and to select inputs and assumptions that are relevant and supportable as of the quantitative testing date. The Company utilized valuation specialists to assist in developing the estimates of fair value of each reporting unit. The presence of management judgment, including the selection of significant inputs and assumptions, and the use of valuation specialists, caused the audit procedures associated with the estimation of fair value of the aforementioned reporting units to be especially challenging and to require the use of auditor judgment in determining the extent of audit effort, including the need to involve professionals having valuation expertise.

Our audit procedures related to the estimation of fair value of the Stimulation Services and Haynesville Proppant Production reporting units included the following, among others.

/s/ GRANT THORNTON LLP

We have served as the Company’s auditor since 2018.

Dallas, Texas

March 15, 2024

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and the Board of Directors

Flotek Industries, Inc.:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Flotek Industries, Inc. and subsidiaries (the Company) as of December 31, 2022 and 2021, the related consolidated statements of operations, comprehensive loss, cash flows, and stockholders’ equity for each of the years in the two-year period ended December 31, 2022, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the years in the two-year period ended December 31, 2022, in conformity with U.S. generally accepted accounting principles.

Going Concern

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, the Company has suffered recurring operating losses and negative cash flows from operations that raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 1. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Change in Accounting Principle

As discussed in Note 2 to the consolidated financial statements, the Company has changed its method of accounting for convertible instruments as of January 1, 2022 due to the adoption of ASU No. 2020-06, Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Recoverability of contract assets

As described in Note 2 to the Company’s consolidated financial statements, the Company’s contract assets represent consideration issued in the form of convertible notes and other incremental costs related to obtaining a contract with ProFrac Services, LLC, a related party customer. The contract assets are tested for recoverability on a recurring

basis and the Company will recognize an impairment loss to the extent that the carrying amount of the contract assets exceeds the amount of revenue the Company expects to receive in the future for the transfer of goods under the long-term supply agreement and the amendment to that agreement (collectively, the ProFrac Agreement) less the direct costs that relate to providing those goods in the future. As described in Note 4, the Company had recorded contract assets, net of $79.7 million as of December 31, 2022.

We identified the evaluation of the recoverability of contract assets as a critical audit matter. There was subjective auditor judgment in evaluating the key assumptions used in the Company’s contract asset recoverability assessment, specifically the forecasted product revenue and related forecasted costs to provide products over the term of the ProFrac Agreement.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design of certain internal controls related to the Company’s contract assets recoverability assessment, including controls over the development of forecasted revenue and costs over the term of the ProFrac Agreement. To assess the Company’s ability to forecast revenue and costs, we compared revenue and cost forecasts for the current year to actual results. We performed sensitivity analyses over the Company’s contract asset recoverability assessment by evaluating the effect of changes in the forecasted revenue and costs over the term of the ProFrac Agreement. We assessed the reasonableness of forecasted revenue and costs by considering whether such amounts were consistent with evidence obtained in other areas of the audit.

/s/ KPMG LLP

We have served as the Company’s auditor since 2021.

Houston, Texas
March 22, 2023
 

ProFrac Holding Corp.

CONSOLIDATED BALANCE SHEETS

(in millions, except per share amounts or where otherwise noted)

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

ProFrac Holding Corp.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per share amounts)