Nine Energy Service, Annual Report 2022

Plain-text annual report

A L I G N E D N I N E E N E R G Y S E R V I C E , I N C . 2 0 2 2 A N N U A L R E P O R T V I S I O N A L I G N E D SUCCESS COMES WITH MANY MOVING PARTS. BY DESIGN AND THROUGH DISCIPLINE, NINE BRINGS THOSE PARTS TOGETHER TO REVEAL A VISION OF UNPRECEDENTED CLARIT Y. Dear Fellow Shareholder, I always like to start our communication with a reminder of Nine’s three-tiered strategy: 1 Building a completion services company that couples excellent service and forward-leaning technology to help our customers lower their cost to complete. 2 Creating an asset- and labor-light business with higher barriers to entry. 3 Providing technologies and services that reduce greenhouse gas (GHG) emissions for our customers. I N D U S T RY OV E RV I E W In 2022, the broader global market was extremely and OFS companies lacked capital to invest in new volatile, still plagued by supply chain constraints and or existing equipment. The labor market remained labor shortages. Companies and families managed extremely constrained. These two factors drove pricing inﬂationary pressures not seen in decades, marked leverage back toward service providers, as customer by rising interest rates, causing uncertainty and concerns expanded from cost of service to availability recessionary fears to rise. The U.S. energy industry saw of service. This shift allowed OFS companies to grow the global demand for oil and gas begin to increase as revenue, and drive proﬁtability. most of the world emerged from COVID lockdowns. The war in Ukraine, capital discipline amongst U.S. producers, and production discipline by OPEC+ created upward pressure on commodity prices. As an industry, we continue to innovate, striving to reduce the time and cost of producing oil and gas — in a cleaner and safer way. We are always looking for new technologies and operational approaches that 2022 resulted in strong performance across the oilﬁeld reduce GHG emissions, without sacriﬁcing ﬁnancial services (OFS) space. While overall frac and rig activity returns, service execution or safety. For the energy were up year over year, I would categorize 2022 as industry, this will be a key focus for many years more of a pricing story. OFS began to increase not only to come. revenue, but proﬁtability as well. Underinvestment in OFS equipment kept oilﬁeld equipment undersupplied, NINE REVENUE CHANGE 70% AVERAGE U.S. RIG COUNT TOTAL U.S. COMPLETIONS * ** INCREASE Y/Y INCREASE Y/Y INCREASE Y/Y *Source Baker Hughes **Source EIA Nine Energy Service Annual Report t 1 2 0 2 2 Y E A R  I N  R E V I E W In our 2021 Annual Report, we outlined our Among all current employees hired prior to 2020, the 2022 priorities as 1) People, People, People, average tenure is approximately eight years. We will 2) Driving Proﬁtability Through Innovative continue to ensure Nine is a place that helps improve Technology and Service Execution, 3) ESG and the lives of our employees through professional and 4) Managing Liquidity. ﬁnancial advancements. People, People, People 1 We are an oilﬁeld services company, and people are our most important assets. Equipment rusts and 2 Drive Proﬁtability through Innovative Technology and Service Execution technology becomes obsolete without the proper team Year over year, we increased our revenue by ~70%, in place. Despite extremely difficult and volatile cycles, our adjusted EBITDA by over 17x and increased our we maintained the core of our team, which now allows adjusted EBITDA margin from 1% to 16%. Our 2022 us to rebound with the market. There is no question in incremental adjusted EBITDA margin1 was ~36%, and my mind that this team enabled us to accomplish all of we generated Return on Invested Capital of ~16%. We our technological advances, ﬁnancial growth, service accomplished this astonishing growth while navigating execution and excellent safety scores in 2022. Often, I am asked how we maintain employees in a very inﬂationary pressures on both the supply chain, as well as labor constraints and new-hire employee turnover. cyclical business. Nine is a meritocracy. We respect Our growth was driven through increased volumes hard work, innovation and taking initiative—we reward within our new downhole technologies, as well as that with competitive pay, career progression, training proﬁtable activity growth and price increases within and excellent health care. This relationship with our team is evidenced in the tenure of our employees. our service lines. In 2022, we once again increased market share, growing our percentage of U.S. stages completed from ~18% in 2021 to ~20% in 20222. CONTINUED EXCELLENCE IN SAFETY TOTAL RECORDABLE INCIDENT RATE (TRIR) SCORES EXCELLENT NINE EMPLOYEE BENEFITS 0. 8 8 0.77 (cid:104) Free Healthcare for Single Employees (cid:104)(cid:3)$6,000 Annual Family Savings in Healthcare 0.30 0.48 0 .41 (cid:104)(cid:3)24/7 Telemedicine Anytime/Anywhere (cid:104)(cid:3)100% Coverage for IVF Treatment 2018 2019 2020 2021 20 22 2 Nine Energy Service Annual Report 1 Change in adjusted EBITDA divided by change in revenue 2 Management estimates of Nine frac stages relative to industry frac stages based on Spears & Associates, Q4 2022 People We respect hard work, innovation and taking initiative—and we reward that with competitive pay, career progression, training and excellent health care. Innovation Our growth was driven through increased volumes within our completion tool technologies, as well as proﬁtable activity growth and price increases within our service lines. Nine Energy Service Annual Report 3 In completion tools, we grew the total number ~40%. In wireline, total stages completed increased by of stages completed by ~38% year over year. We ~26% year over year, with the average price per stage remain extremely happy with the performance of increasing by ~18%. our dissolvable plugs, increasing the total number of Dissolvable Stinger units sold by ~42% year over year. We also maintained a strong composite plug business, Environmental, Social and 3 Governance (ESG) increasing the total number of composite plugs sold by Through the development of internal policies, ~44% year over year. We estimate that in 2022, Nine procedures and measurements, Nine has made held ~20% of the total U.S. plug market, including both a substantial commitment to ESG, as well as an composite and dissolvable plugs. investment in new technologies that help reduce Our cementing service line increased the total number GHG emissions. of jobs completed by ~50% year over year, while also During 2022, identifying and quantifying our GHG increasing our average price per job by ~34%. This emissions was a top priority for Nine. For 2021, we growth was fueled by our state-of-the-art lab facilities were able to quantify these emissions for the ﬁrst creating proprietary and highly technical cement time and are currently in the process of quantifying slurries, coupled with precise wellsite execution. our 2022 emissions. Through this process, we are We also saw growth in coiled tubing and wireline. Coiled tubing increased days worked by ~37% year over year, with the average day rate increasing by identifying gaps and procedures to make the collection of this data more accurate and efficient, as well as developing a strategy on how to reduce our emissions moving forward. In conjunction with this, we have NINE'S GROWTH ACROSS DIVISIONS MARKET SHARE OF U.S. STAGES COMPLETED 18% TO 20% 2 TOTAL NUMBER OF DISSOLVABLE STINGER UNITS SOLD 42% TOTAL NUMBER OF COMPOSITE PLUGS SOLD 44% INCREASE FROM 2021 TO 2022 INCREASE Y/Y INCREASE Y/Y 4 Nine Energy Service Annual Report begun formalizing our commitment and approach to ESG has been and will continue to be a priority for sustainability, disclosing our sustainability principles, Nine, and we look forward to sharing more of our material management and a number of other ESG- ﬁndings and strategy moving forward. related priorities. We have also prioritized investing in technologies that drive proﬁtability for the company, while helping to reduce emissions. In 2022, we converted two hydraulic wireline units to electric and have made a commitment to convert four more in 2023. With the electric units there is signiﬁcant savings on both diesel and maintenance costs for Nine. Our dissolvable plug signiﬁcantly reduces GHG emissions, and during 2022, we introduced Nine’s dissolvable pumpdown ring. The dissolvable pumpdown ring has been shown to reduce horsepower requirements by ~48%, water required to pump the plug to set at depth by ~28% and diesel fuel usage by ~42%. Managing Liquidity 4 I am extremely happy with our team’s discipline and approach to managing liquidity while simultaneously de-levering the company. During 2022, we used free cash ﬂow to repurchase additional bonds, and took more than $90 million of term debt off of the balance sheet over the last several years. While doing this, we maintained strong liquidity throughout one of the most volatile environments we have ever faced. Additionally, the asset-light nature of our business reduces our CapEx needs, helping to generate more free cash ﬂow. All of these initiatives, aided in the execution of our successful reﬁnancing in January of 2023. This new capital structure provides increased optionality to unlock equity value, and we intend to continue to de-lever moving forward. 44% CEMENTING SERVICE LINE TOTAL NUMBER OF JOBS COMPLETED 50% COILED TUBING DAYS WORKED 37% WIRELINE TOTAL STAGES COMPLETED 26% INCREASE Y/Y INCREASE Y/Y INCREASE Y/Y Nine Energy Service Annual Reportt 5 2023 P R I O R I T I E S A N D O P P O RT U N I T I E S We remain optimistic for 2023 and believe operators know today, we do anticipate activity growth in 2023. will need to drill more wells to keep production ﬂat. The management team intends to use any free cash Overall market fundamentals remain supportive for a ﬂow generation towards de-levering. longer cycle with both U.S. operators and OPEC taking a more disciplined approach to production. Nine has one of the top completion tool portfolios in the U.S. In 2023, we will be focused on enhancing Our top priorities for 2023 include: 1) Generating and growing our domestic tool portfolio, as well as Free Cash Flow and De-Levering; 2) Increasing our expanding our completion tool footprint into the Domestic and International Tools Business; 3) Adding international markets. In the U.S., we are partnering Scale; and 4) ESG. with exceptional engineers to penetrate the refrac Since 2018, we have been very clear about Nine’s strategy to become a more asset- and labor-light business. As we have shifted more of our top line exposure to both completion tools and cementing, we are starting to see the impact this has on our free cash ﬂow generation. Our business has been designed to reduce our labor and capital needs, increasing cash ﬂow and reducing capital allocation risk. With what we market. We are constantly changing and updating our composite and dissolvable plugs to be more efficient for our customers and less expensive for Nine to manufacture. Simultaneously, we are increasing our reach into the international markets. In 2022 ~4% of our revenue was generated outside North America and we believe there is room to grow this share. NINE ANNUAL CAPEX SPEND ($MM) $4 5 2017 $54 4 8% $53 2018 $ 827 6% $62 2019 $83 3 7% $ 10 2016 $282 4% REVENUE ($MM) CAPEX AS A % OF REV $10 20 20 $ 311 3 % $ 15 2021 $34 9 4 % $ 32 $30 1 2022 $593 5 % 20 23 E $667 2 4% 1 Assumes midpoint of 2023 Management CapEx guidance; 2 Assumes Q4 2022 annualized revenue 6 Nine Energy Service Annual Report N I N E ’S P R E M I E R C OM P L E T I O N Tool Portfolio ST I N G E R ™ D I SS O LVA B L E F R AC P L U G S CO R P I O N ™ COM P O S I T E F R AC P L U G ST I N G E R ™ E X T E N D E D R A N G E F R AC P L U G of tools R E F R AC L I N E R S B R E A K T H R U ™ B A R R I E R VA LV E Nine Energy Service Annual Report 7 Adding scale can come in many forms, including We are focused on market share gains, strategic market share gains, organic growth/geographic price increases, the development of our completion expansion and de-levering M&A. We have proven our tool reach domestically and internationally and ability to grow through all the available channels and maintaining our geographic and service line diversity. will be focused on determining what form of growth The service lines we operate are differentiated and will provide the greatest returns for our shareholders aligned with our customers on their operational and moving forward. ESG priorities. Our strong margins and cash ﬂow Being able to quantify our GHG emissions for the ﬁrst time was a signiﬁcant milestone for Nine. We light strategy. demonstrate the impact of Nine’s asset- and labor- will continue in this direction, improving collection The amplitude and velocity of these cycles is intense; processes and accuracy, as well as developing goals however, the most consistent factor in Nine is our team. and plans for reducing our emissions moving forward. It is an honor to lead this company and work side by We will continue to invest in ESG technology. Our side with our incredible people. I want to thank our R&D teams across the organization are working on investors, customers and employees for your support. downhole tools, cement slurries and other technology that can help improve operations while reducing emissions. As I mentioned before, we are also Best regards, allocating capital to the further electriﬁcation of our wireline ﬂeet. Ann G. Fox 8 Nine Energy Service Annual Report UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K (Mark One) È ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2022 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: 001-38347 NINE ENERGY SERVICE, INC. (Exact name of registrant as specified in its charter) Delaware (State or other jurisdiction of incorporation or organization) 80-0759121 (I.R.S. Employer Identification No.) 2001 Kirby Drive, Suite 200 Houston, TX 77019 (Address of principal executive offices) (281) 730-5100 (Registrant’s telephone number, including area code) Securities registered pursuant to Section 12(b) of the Act: Title of each class Trading Symbol(s) Name of each exchange on which registered Common Stock, par value $0.01 per share NINE New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ‘ No È 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 È 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 È 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 È No ‘ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. ‘ Large accelerated filer ‘ Accelerated filer È Non-accelerated filer È Smaller reporting company Emerging growth company È 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 È The aggregate market value of the registrant’s common stock held by non-affiliates of the registrant on the last business day of the registrant’s most recently completed second fiscal quarter (based on the closing sales price on the New York Stock Exchange on June 30, 2022) was $47,805,208. The number of shares of the registrant’s common stock outstanding at March 3, 2023 was 34,721,266. DOCUMENTS INCORPORATED BY REFERENCE Information called for in Part III of this Annual Report on Form 10-K is incorporated by reference to the registrant’s Definitive Proxy Statement for its 2023 Annual Meeting of Stockholders. TABLE OF CONTENTS PART I Item 1. Item 1A. Item 1B. Item 2. Item 3. Item 4. PART II Item 5. Item 6. Item 7. Item 7A. Item 8. Item 9. Item 9A. Item 9B. Item 9C. PART III Item 10. Item 11. Item 12. Item 13. Item 14. PART IV Item 15. Item 16. Business Risk Factors Unresolved Staff Comments Properties Legal Proceedings Mine Safety Disclosures Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities [Reserved] Management’s Discussion and Analysis of Financial Condition and Results of Operations Quantitative and Qualitative Disclosures About Market Risk Financial Statements and Supplementary Data Changes in and Disagreements with Accountants on Accounting and Financial Disclosure Controls and Procedures Other Information Disclosure Regarding Foreign Jurisdictions that Prevent Inspections Directors, Executive Officers and Corporate Governance Executive Compensation Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters Certain Relationships and Related Transactions, and Director Independence Principal Accountant Fees and Services Exhibit and Financial Statement Schedules Form 10-K Summary 1 13 34 34 35 35 36 36 37 50 51 52 52 52 53 54 54 54 54 54 55 58 CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS This Annual Report on Form 10-K (this “Annual Report”) contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans, and objectives of management are forward- looking statements. When used in this Annual Report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. All forward-looking statements speak only as of the date of this Annual Report; we disclaim any obligation to update these statements unless required by law, and we caution you not to place undue reliance on them. Although we believe that our plans, intentions, and expectations reflected in or suggested by the forward-looking statements we make in this Annual Report are reasonable, we can give no assurance that these plans, intentions, or expectations will be achieved. We disclose important known factors that could cause our actual results to differ materially from our expectations under “Risk Factors” in Item 1A of Part I and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of Part II of this Annual Report. Additional risks or uncertainties that are not currently known to us, that we currently deem to be immaterial, or that could apply to any company could also materially adversely affect our business, financial condition, or future results. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf. 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. • Our business is cyclical and depends on capital spending and well completions by the onshore oil and natural gas industry, and the level of such activity is volatile and strongly influenced by current and expected oil and natural gas prices. If the prices of oil and natural gas decline, our business, financial condition, results of operations, cash flows, and prospects may be materially and adversely affected. Significant factors that are likely to affect near-term commodity prices include actions by the members of the Organization of the Petroleum Exporting Countries (“OPEC”) and other oil exporting nations; U.S. energy, monetary, and trade policies; the pace of economic growth in the U.S. and throughout the world; and geopolitical and economic developments in the U.S. and globally, including conflicts, instability, acts of war, and terrorism. • Inflation may adversely affect our financial position and operating results; in particular, cost inflation with labor or materials could offset any price increases for our products and services. • If we are unable to attract and retain key employees, technical personnel, and other skilled and qualified workers, our business, financial condition, or results of operations could suffer. • We may be unable to maintain existing prices or implement price increases on our products and services, and intense competition in the markets for our dissolvable plug products may lead to pricing pressures, reduced sales, or reduced market share. • Our substantial debt obligations could have significant adverse consequences on our business and future prospects, and restrictions in our debt agreements could limit our growth and our ability to engage in certain activities. • Our current and potential competitors may have longer operating histories, significantly greater financial or technical resources, and greater name recognition than we do. • Our operations are subject to conditions inherent in the oilfield services industry, such as equipment defects, liabilities arising from accidents or damage involving our fleet of trucks or other equipment, explosions and uncontrollable flows of gas or well fluids, and loss of well control. • If we are unable to accurately predict customer demand, including that of our international customers, or if customers cancel their orders on short notice, we may hold excess or obsolete inventory, which would reduce gross margins. Conversely, insufficient inventory would result in lost revenue opportunities and potentially loss of market share and damaged customer relationships. • We are dependent on customers in a single industry. The loss of one or more significant customers, including certain of our customers outside of the U.S., could adversely affect our financial condition, prospects, and results of operations. Sales to customers outside of the U.S. also exposes us to risks inherent in doing business internationally, including political, social, and economic instability and disruptions, export controls, economic sanctions, embargoes or trade restrictions, and fluctuations in foreign currency exchange rates. • We may be subject to claims for personal injury and property damage or other litigation, which could materially adversely affect our financial condition, prospects, and results of operations. • We are subject to federal, state, and local laws and regulations regarding issues of health, safety, and protection of the environment. Under these laws and regulations, we may become liable for penalties, damages, or costs of remediation or other corrective measures. Any changes in laws or government regulations could increase our costs of doing business. • Our success may be affected by the use and protection of our proprietary technology as well as our ability to enter into license agreements. There are limitations to our intellectual property rights and, thus, our right to exclude others from the use of our proprietary technology. • Our success may be affected by our ability to implement new technologies and services. • Significant ownership of our common stock by certain stockholders could adversely affect our other stockholders. • Our future financial condition and results of operations could be adversely impacted by asset impairment charges. • Increased attention to climate change and conservation measures may reduce oil and natural gas demand, and we face various risks associated with increased activism and related litigation against oil and natural gas exploration and development activities. • Seasonal and adverse weather conditions adversely affect demand for our products and services. PART I ITEM 1. BUSINESS OVERVIEW Nine Energy Service, Inc. (either individually or together with its subsidiaries, as the context requires, the “Company,” “Nine,” “we,” “us,” and “our”) is a Delaware corporation that was formed in February 2013 through a combination of three service companies owned by SCF Partners, L.P. or its affiliates. Nine is a leading completion services provider that targets unconventional oil and gas resource development across North American basins and abroad. We partner with our exploration and production (“E&P”) customers to design and deploy downhole solutions and technology to prepare horizontal, multistage wells for production. We focus on providing our customers with cost-effective and comprehensive completion solutions designed to maximize their production levels and operating efficiencies. We believe our success is a product of our culture, which is driven by our intense focus on performance and wellsite execution as well as our commitment to forward-leaning technologies that aid us in the development of smarter, customized applications that drive efficiencies. We provide our comprehensive completion solutions across a diverse set of well-types, including on the most complex, technically demanding unconventional wells. Modern, high-intensity completion techniques are a more effective way for our customers to maximize resource extraction from horizontal oil and gas wells. These completion techniques provide improved estimated ultimate recovery per lateral foot and a superior return on investment by decreasing cycle time, which make them attractive to operators. We compete for the most intricate and demanding projects, which are characterized by extended reach horizontal laterals, increased stage counts per well, multi-well pad development, and increased proppant loading per lateral foot. As stage counts per well and wells per pad increase, so do our operating leverage and returns, as we are able to complete more jobs and stages with the same number of units and crews. Service providers for these demanding projects are selected based on their technical expertise and ability to execute safely and efficiently. As our customers continue to improve operational efficiencies in completions design, increasing its complexity and difficulty, oilfield service selection becomes much more critical and selective. We offer a variety of completion applications and technologies to match customer needs across the broadest addressable completions market. Our comprehensive well solutions range from cementing the well at the initial stages of the completion, preparing the well for stimulation, isolating all the stages of an extended reach lateral, and the drilling out of isolation tools. Our completion techniques are specifically tailored to the customer and geology of each well. At the initial stage of a well completion, our lab facilities produce customized cementing slurries used to secure the production casing to ensure well integrity throughout the life of the well. Once the casing is in place, we utilize our proprietary tools at the toe (end) of the well, often called stage one, to prepare for the well stimulation process. Following stage one, we perform plug-and-perf completions using a wireline or electric wireline truck and reel, as well as our composite or dissolvable frac plugs. Through our wireline units, we provide plug-and-perf services that, when combined with our fully-composite or dissolvable frac plugs, create perforations to isolate and divert the fracture to the correct stage. Our completion tool technology focuses on composite and dissolvable frac plugs that isolate stages in a completion but also includes a number of other patented technologies sold in North America and abroad. Our equipment also includes large-diameter coiled tubing units that are capable of reaching the farthest depths for the removal of plugs and cleaning of the wellbore to prepare for production. Our website is located at https://nineenergyservice.com, and our investor relations website is located at https:// investor.nineenergyservice.com. The information posted on our website is not incorporated into this Annual Report. Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to reports filed or furnished pursuant to Sections 13(a) and 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), are available free of charge on our investor relations website as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission (the “SEC”). You may also access all of our public filings through the SEC’s website at www.sec.gov. Investors and other interested parties should note that we use our investor relations website to publish important 1 information about us, including information that may be deemed material to investors. We encourage investors and other interested parties to review the information we may publish through our investor relations website, in addition to our SEC filings, press releases, conference calls, and webcasts. OUR SERVICES We derive revenue by providing services integral to the completion of unconventional wells through a full range of tools and methodologies. The following is a description of our primary service offerings and deployment methods: Cementing Services: Our cementing services consist of blending high-grade cement and water with various solid and liquid additives to create a cement slurry that is pumped between the casing and the wellbore of the well. We currently operate four high-quality laboratory facilities capable of designing and testing all of the current industry cement designs. The laboratory facilities operate twenty-four hours a day and are fully staffed by qualified technicians with the latest equipment and modeling software. Additionally, our technicians and engineers ensure that all tests are performed to American Petroleum Institute specifications and results are delivered to customers promptly. Our cement slurries are designed to achieve the proper cement thickening time, compressive strength, and fluid loss control. Our slurries can be modified to address a wide range of downhole needs of our E&P customers, including varying well depths, downhole temperatures, pressures, and formation characteristics. We deploy our slurries by using our customized design twin-pumping units, which are fully redundant, containing two pumps, two hydraulic systems, two mixing pumps, and two electrical systems. This customized design significantly decreases our risk of downtime due to mechanical failure and eliminates the necessity of having an additional cementing unit on standby. We have invested in the highest quality cementing equipment. From January 2018 through December 2022, we completed approximately 18,100 cementing jobs, with an on-time rate of approximately 90%. Punctuality of service has become one of the primary metrics that E&P operators use to evaluate the cementing services they receive. Key contributors to our 90% on-time rate include our lab capabilities, personnel, close proximity to our customers’ acreage, dual-sided bulk loading plants, and our service-driven culture. Completion Tools: We provide downhole solutions and technology used for multistage completions. Our comprehensive completion service offerings are mostly comprised of composite and dissolvable frac plugs in a variety of sizes to isolate stages during plug-and-perf operations. We have coupled patented tool designs with proprietary materials for our dissolvable offering, enabling us to serve the entire addressable plug market. With this ability, we have traditional and long-range plugs to address every type of wellbore situation. Our frac plug technology is complemented by our unconventional open hole and cemented completion tool products, such as liner hangers and accessories, fracture isolation packers, frac sleeves, stage one prep tools, casing flotation tools, specialty open hole float equipment, disk subs, composite cement retainers, and centralizers. Our systems provide completion efficiencies at the wellsite by reducing our customers’ equipment needs and stimulation time and allowing for specific zonal treatment. Our dissolvable frac plugs help operators reduce cycle times to bring production online faster, decrease the amount of equipment and people needed on location, and significantly reduce carbon emissions compared to a traditional composite plug completion. Through these reductions in cycle time, our dissolvable plugs can help increase our customers’ internal rate of return and provide a safer and more efficient working environment. From January 2018 through December 2022, we deployed approximately 377,100 isolation, stage one, and casing flotation tools. Wireline Services: Our wireline services involve the use of a wireline or electric wireline unit equipped with a spool of wireline that is unwound and lowered into oil and gas wells to convey specialized tools or equipment for well completion, well intervention, or pipe recovery. We operate a fleet of modern and “fit-for-purpose” cased hole wireline units designed for operating in unconventional completion operations. Our operation is equipped with the latest technology utilized to service long lateral completions, including head tension tools, ballistic release tools, and addressable switches. We have converted and continue to convert our hydraulic wireline units to electric, which significantly reduces carbon emissions and the use of diesel. We currently have wireline units equipped with Coated 2 Line, which is a coated wireline that significantly reduces injector oil use. Offering a lower dynamic coefficient of friction, Coated Line Wireline requires less pump down fluid to operate and is more conducive for reaching further depths in longer laterals. The majority of our wireline work consists of plug-and-perf completions, which is a multistage well completion technique for cased-hole wells that consists of deploying perforating guns to a specified depth. We deploy proprietary specialized tools like our fully-composite and dissolvable frac plugs through our wireline units. From January 2018 through December 2022, we completed approximately 140,700 wireline stages with a success rate of approximately 99%. Coiled Tubing Services: Coiled tubing services perform wellbore intervention operations utilizing a continuous steel pipe that is transported to the wellsite wound on a large spool in lengths of up to 30,000 feet. Coiled tubing provides a cost-effective solution for well work due to the ability to deploy efficiently and safely into a live well using specialized well-control equipment. The live well work capability limits the customer’s risk of formation damage associated with “killing” a well (the temporary placement of heavy fluids in a wellbore to keep reservoir fluids in place), while allowing for safer operations due to minimal equipment handling. Coiled tubing facilitates a variety of services in both new and old wells, such as milling, drilling, fishing, production logging, artificial lift, cementing, and stimulation. Our coiled tubing units carry data acquisition and dissemination technology, allowing our customers to monitor jobs via a web interface. Our “extended reach” units are capable of reaching the toe of wells with total measured depths of 24,000 feet and beyond, including lateral lengths in excess of 12,500 feet, keeping pace with the industry’s most challenging downhole environments. While we specialize in larger-diameter (2 3/8” and 2 5/8”) coiled tubing units, we also offer 2” and 1 1/4” diameter solutions to our customers. From January 2018 through December 2022, we have performed approximately 5,890 jobs and deployed more than 160 million running feet of coiled tubing, with a success rate of over 99%. GEOGRAPHIC AREAS OF OPERATION We operate in all major onshore basins in the U.S., including the Permian Basin, Marcellus and Utica Shales, Eagle Ford Shale, DJ Basin, SCOOP/STACK Formation, Bakken Formation, and Haynesville Formation as well as the Western Canada Sedimentary Basin in Canada. We provide our services through strategically placed operating facilities located in-basin throughout the U.S. This local presence allows us to quickly respond to customer demands and operate efficiently. Additionally, through our extensive footprint, we are able to track and implement best practices around completion trends and technology across all divisions and geography. A portion of completion tool revenue is generated from outside of North America, and international completion tools are an important part of our revenue stream. We believe that our strategic geographic diversity will benefit us as activity increases or decreases in select basins by helping to mitigate basin and commodity-risk. Our broad geographic footprint provides us with exposure to potential increases in drilling and completion activity and will allow us to opportunistically pursue new business in basins with the most active drilling environments. SEASONALITY Our operations are subject to seasonal factors, and our overall financial results reflect seasonal variations. Specifically, we typically have experienced a pause by our customers around the holiday season in the fourth quarter, which may be compounded as our customers exhaust their annual capital spending budgets towards year end. Additionally, our operations are directly affected by weather conditions. During the winter months (portions of the first and fourth quarters) and periods of heavy snow, ice, or rain, particularly in the northeastern U.S., North Dakota, Rockies, and western Canada, our customers may delay operations or we may not be able to operate or move our equipment between locations. Also, during the spring thaw, which normally starts in late March and continues through June, some areas, primarily in western Canada, impose transportation restrictions to prevent damage caused 3 by the spring thaw. Throughout the year, heavy rains adversely affect activity levels because well locations and dirt access roads can become impassible in wet conditions. Weather conditions may also negatively affect our customers’ activity levels. SALES AND MARKETING Our sales activities are conducted through a network of sales representatives and business development personnel, which provides us coverage at both the corporate and field level of our customers. We have a technical sales organization with expertise and focus within our specific service lines. Sales representatives work closely with local operations managers to target potential opportunities through strategic focus and planning. Customers are identified as targets based on their drilling and completion activity, geographic location, and economic viability. Our marketing activities are performed internally with input and guidance from a third-party marketing agency. Our strategy is based on building a strong brand though multiple media outlets including our website, select social media accounts, print and online advertisements, billboard advertisements, press releases and various industry- specific conferences, publications, and lectures. CUSTOMERS Our customer base includes a broad range of integrated and independent E&P companies. For the year ended December 31, 2022, our top five customers collectively accounted for approximately 21% of our revenues. Demand for our services and products is cyclical and substantially dependent upon activity levels in the oil and gas industry, particularly our customers’ willingness to spend capital on the exploration for and development of oil and natural gas. Our customers’ spending plans are generally based on their outlook for near-term and long-term commodity prices. As a result, the demand for our services and products is highly sensitive to current and expected commodity prices. COMPETITION We provide our services and products across the U.S., Canada, and abroad, and we compete against different companies in each service and product line we offer. Our competition includes many large and small oilfield service companies, including the largest integrated oilfield services companies. We believe that the principal competitive factors in the markets we serve are technology offerings, wellsite execution, service quality, technical expertise, equipment capacity, work force competency, efficiency, safety record, reputation, and experience. Additionally, projects are often awarded on a bid basis, which tends to create a highly competitive environment. We seek to differentiate our company from our competitors by delivering the highest-quality services, technology, and equipment possible, coupled with superior execution and operating efficiency in a safe working environment. By focusing on cultivating our existing customer relationships and maintaining our high standard of customer service, technology, safety, performance, and quality of crews, equipment, and services, we believe we are differentiated in a competitive market. Our major competitors include Halliburton Company, Schlumberger Limited, NCS Multistage, NexTier Oilfield Solutions, KLX Energy Services Holdings, Innovex, and a significant number of private and locally- oriented businesses. SUPPLIERS We purchase a wide variety of raw materials, parts, and components that are manufactured and supplied for our operations from various suppliers. While we are not dependent on any single supplier for those materials, parts, or components, certain product lines depend on a limited number of third-party suppliers and vendors. During the year ended December 31, 2022, no supplier of the materials used in our services provided over 10% of our materials or equipment as a percentage of overall costs. To date, we have generally been able to obtain the equipment, parts, and supplies necessary to support our operations on a timely basis. While we believe that we will be able to make satisfactory alternative arrangements in the event of any interruption in the supply of these materials and/or products by one of our suppliers, we may not always be able to make alternative arrangements. In addition, certain materials for which we do not currently have 4 long-term supply agreements could experience shortages and significant price increases in the future. As a result, we may be unable to mitigate any future supply shortages, and our results of operations, prospects, and financial condition could be adversely affected. RESEARCH & TECHNOLOGY, INTELLECTUAL PROPERTY Our sales and earnings are influenced by our ability to successfully introduce new or improved products and services to the market. We believe we have become a “go-to” provider for piloting new technologies because of our service quality and offering, execution at the wellsite, and geographic footprint. Our engineering and technology efforts are focused on providing efficient and cost-effective solutions to maximize production for our customers across major North American onshore basins and abroad. We have dedicated resources focused on internally developing new technology and equipment and evolving our existing proprietary tools, as well as resources focused on sourcing and commercializing new technologies through mergers and acquisitions and strategic partnerships, to stay ahead of industry trends and achieve lower completion and production costs for our customers. We have developed a suite of proprietary downhole tools, products, and techniques through both internal resources, as well as mergers and acquisitions and strategic partnerships with manufacturers and engineering companies looking for a reliable and expansive channel to market. In these partnerships, we have exclusive rights to market and sell technology unavailable to any other service providers in the designated regions, and we sell the technology directly to the customer and order from the manufacturer on an as-needed basis, with no minimum volume requirements and without having to hold excess inventory. These strategic partnerships provide us and our customers with access to unique downhole technology from independent innovators while allowing us to minimize exposure to potential technology adoption risks and the significant costs associated with developing and implementing research and development internally. Although in the aggregate our patents, licenses, and strategic partnerships are important to us, we do not regard any single patent, license, or strategic partnership as critical or essential to our business as a whole. In general, we depend on our technological capabilities, customer service-oriented culture, and application of our know-how to distinguish ourselves from our competitors, rather than our right to exclude others through patents or exclusive licenses. We also consider the quality and timely delivery of our products, the service we provide to our customers, and the technical knowledge and skill of our personnel to be more important than our registered intellectual property in our ability to compete. RISK MANAGEMENT AND INSURANCE Our operations are subject to hazards inherent in the oil and natural gas industry, including, but not limited to, accidents, blowouts, explosions, craterings, fires, oil spills, and hazardous materials spills. These conditions can cause personal injury or loss of life; damage to, or destruction of, property, the environment, and wildlife; and the suspension of our or our customers’ operations. In addition, claims for loss of oil and 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 us 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 our efforts to maintain high safety standards, from time to time, we have suffered accidents, and there is a risk that we will experience accidents in the future. In addition to the property and personal losses from these accidents, the frequency and severity of these incidents affect our operating costs, insurability, and relationships with customers, employees, and regulatory agencies. In particular, in recent years many of our large customers have placed an increased emphasis on the safety records of their service providers. Any significant increase in the frequency or severity of these incidents, or the general level of compensatory payments, 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. 5 We maintain insurance coverage of types and amounts that we believe to be customary in the industry including workers’ compensation, employer’s liability, claims-based pollution, umbrella, comprehensive commercial general liability, business automobile, and property. Our insurance coverage may be inadequate to cover our liabilities. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable and commercially justifiable or on terms as favorable as our current arrangements. We endeavor to allocate potential liabilities and risks between the parties in our Master Service Agreements (“MSAs”). We retain the risk for any liability not indemnified by our customers in excess of our insurance coverage. These MSAs delineate our and our customers’ respective warranty and indemnification obligations with respect to the services we provide. We endeavor to negotiate MSAs with our customers that provide, among other things, that we and our customers assume (without regard to fault) liability for damages to our respective personnel and property. For catastrophic losses, we endeavor to negotiate MSAs that include industry-standard carve-outs from the knock-for-knock indemnities. Additionally, our MSAs often provide carve-outs to the “without regard to fault” concept that would permit, for example, us to be held responsible for events of catastrophic loss only if they arise as a result of our gross negligence or willful misconduct. Our MSAs typically provide for industry-standard pollution indemnities, pursuant to which we assume liability for surface pollution associated with our equipment and originating above the surface (without regard to fault), and our customer assumes (without regard to fault) liability arising from all other pollution, including, without limitation, underground pollution and pollution emanating from the wellbore as a result of an explosion, fire, or blowout. This description of our MSAs is a summary of the material terms of the typical MSA that we have in place and does not reflect every MSA that we have entered into or may enter into in the future, some of which may contain indemnity structures and risk allocations between our customers and us that are different than those described here. EMPLOYEES As of December 31, 2022, we had 1,212 employees, all of which were full-time. We are not a party to any collective bargaining agreements. REGULATORY MATTERS Our operations are subject to numerous stringent and complex laws and regulations at the U.S. federal, state, and local levels governing the discharge of materials into the environment, environmental protection, and health and safety aspects of our operations. In addition, due to our operations in Canada, we are subject to Canadian environmental statutes and regulations. Failure to comply with these laws and regulations or to obtain or comply with permits may result in the assessment of administrative, civil, and criminal penalties, imposition of remedial or corrective action requirements, and the imposition of injunctions or other orders to prohibit certain activities, restrict certain operations, or force future compliance with environmental requirements. There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbons, other hazardous substances, and wastes, as a result of air emissions and wastewater discharges related to our operations, and because of historical operations and waste disposal practices. Spills or other releases of regulated substances, including such spills and releases that occur in the future, could expose us to material losses, expenditures, and liabilities under applicable environmental laws and regulations. Under certain of such laws and regulations, we could be held strictly and jointly and severally liable for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination and even if our operations met previous standards in the industry at the time they were conducted. The following is a summary of some of the existing laws, rules, and regulations to which we are subject. Hazardous Substances and Waste Handling The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the management, generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous wastes. Under the guidance issued by the U.S. Environmental Protection Agency (the “EPA”), the individual states 6 administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. We are required to manage the disposal of hazardous and non-hazardous wastes in compliance with RCRA and analogous state laws. RCRA currently exempts many E&P wastes from classification as hazardous waste if properly handled. Specifically, RCRA excludes from the definition of hazardous waste drilling fluids, produced waters, and most of the other wastes intrinsically associated with the exploration, development, or production of crude oil and natural gas and, instead, these fluids, waters, and wastes are regulated under RCRA’s less stringent non-hazardous waste provisions, state laws, or other federal laws. However, it is possible that certain oil and natural gas E&P wastes now classified as non-hazardous could be classified as hazardous waste in the future. Stricter regulation of wastes generated during our or our customers’ operations could result in increased costs for our operations or the operations of our customers, which could in turn reduce demand for our services and adversely affect our business. Comprehensive Environmental Response, Compensation, and Liability Act The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state laws impose joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and former owner or operator of the site where the release occurred and anyone who transported or disposed or arranged for the transport or disposal of a hazardous substance released at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA and any state analogs may be subject to joint and several and strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources and for the costs of certain health studies. We currently own, lease, or operate numerous properties that have been used for manufacturing and other operations for many years. These properties and the substances disposed or released on them may be subject to CERCLA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial operations to prevent future contamination. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Worker Health and Safety We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (“OSHA”) and comparable state laws, establishing requirements to protect the health and safety of workers. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require maintenance of information about hazardous materials used or produced in operations and provision of this information to employees, state and local government authorities, and citizens. Additionally, the Federal Motor Carrier Safety Administration (the “FMCSA”) regulates and provides safety oversight of commercial motor vehicles, the EPA establishes requirements to protect human health and the environment, and the federal Bureau of Alcohol, Tobacco, Firearms and Explosives establishes requirements for the safe use and storage of explosives. The federal Nuclear Regulatory Commission establishes requirements for the possession and use of radioactive materials, while most states have entered into agreements that allow them to assume licensing and oversight activities for specified classes of such materials. State agencies typically regulate other sources of ionizing and non-ionizing radiation. Substantial fines and penalties can be imposed, and orders or injunctions limiting or prohibiting certain operations may be issued, in connection with any failure to comply with these laws and regulations. Transportation Safety and Compliance At December 31, 2022, we operated a fleet in excess of 550 commercial motor vehicles. As such, we are subject to a number of federal and state laws and regulations, including the Federal Motor Carrier Safety Regulations and Hazardous Material Regulations for interstate travel and comparable state regulations for intrastate travel. Substantial fines and penalties can be imposed and orders or injunctions limiting or prohibiting certain operations may be issued in connection with any failure to comply with laws and regulations relating to the safe operation of commercial motor vehicles. 7 Water Discharges The Federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into federal and state waters. The discharge of pollutants into, and other impacts to, regulated waters, including jurisdictional wetlands, is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The scope of federal jurisdictional reach over waters of the United States has been subject to substantial revision in recent years. In September 2015, the EPA and U.S. Army Corps of Engineers (“Corps”) issued a rule defining the scope of federal jurisdiction over wetlands and other waters of the U.S., which never took effect before being replaced by the Navigable Waters Protection Rule (the “NWPR”) in December 2019. A coalition of states and cities, environmental groups, and agricultural groups challenged the NWPR, which was vacated by a federal district court in August 2021. The EPA is undergoing a two-phase rulemaking process to redefine the definition of waters of the U.S., which could be impacted by the U.S. Supreme Court’s upcoming decision in Sackett v. EPA, a case regarding the proper test in determining whether wetlands qualify as “Waters of the United States” or WOTUS. A final rule, known as “Rule 1,” was announced by the EPA and Corps in December 2022. The EPA and Corps are expected to propose a second rule, known as “Rule 2,” further refining Rule 1 by November 2023 and issue a final rule by July 2024. To the extent a future rule expands the range of properties subject to the Clean Water Act’s jurisdiction, certain energy companies could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas, which in turn could reduce demand for our services. The process for obtaining permits has the potential to delay our operations and those of our customers. Spill prevention, control, and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture, or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of wastewater and storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. The Clean Water Act and analogous state laws provide for administrative, civil, and criminal penalties for unauthorized discharges and, together with the Oil Pollution Act of 1990, impose rigorous requirements for spill prevention and response planning, as well as substantial potential liability, such as strict liability and natural resources damages liability, for the costs of removal, remediation, and damages in connection with any unauthorized discharges. Air Emissions Through the federal Clean Air Act, as amended (“CAA”), and comparable state and local laws and regulations, the EPA regulates emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and modified and existing facilities may be required to obtain additional permits. In June 2016, the EPA finalized regulations establishing New Source Performance Standards, known as Subpart OOOOa, for methane and volatile organic compounds from new and modified oil and natural gas production and natural gas processing and transmission facilities. In September 2020, the EPA finalized two sets of amendments to the 2016 Subpart OOOOa standards. The first, known as the 2020 Technical Rule, reduced the 2016 rule’s fugitive emissions monitoring requirements and expanded exceptions to pneumatic pump requirements, among other changes. The second, known as the 2020 Policy Rule, rescinded the methane-specific requirements for certain oil and natural gas sources in the production and processing segments. On January 20, 2021, President Biden issued an Executive Order directing the EPA to rescind the 2020 Technical Rule by September 2021 and consider revising the 2020 Policy Rule. On June 30, 2021, President Biden signed a Congressional Review Act (the “CRA”) resolution passed by Congress that revoked the 2020 Policy Rule. The CRA did not address the 2020 Technical Rule. On November 15, 2021, the EPA proposed a new rule intended to reduce methane emissions from oil and gas sources. The proposed rule would make the existing regulations in Subpart OOOOa more stringent and create a 8 Subpart OOOOb to expand reduction requirements for new, modified, and reconstructed oil and gas sources, including standards focusing on certain source types that have never been regulated under the CAA (including intermittent vent pneumatic controllers, associated gas, and liquids unloading facilities). In addition, the proposed rule would establish “Emissions Guidelines,” creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by EPA. Under the proposed rule, states would have three years to develop their compliance plan for existing sources, and the regulations for new sources would take effect immediately upon issuance of a final rule. On November 11, 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rule. Among other things, the November 2022 supplemental proposed rule removed an emissions monitoring exemption for small wellhead-only sites and creates a new third-party monitoring program to flag large emissions events, referred to in the proposed rule as “super emitters.” The EPA is expected to issue a final rule by August 2023. As a result of these regulatory changes, the scope of any final methane regulations or the costs for complying with federal methane regulations are uncertain. However, any new regulations implementing stricter permitting requirements could delay or impair our or our customers’ ability to obtain air emission permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties, as well as injunctive relief, for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. Climate Change Numerous reports from scientific and governmental bodies, such as the Sixth Assessment Report of the Intergovernmental Panel on Climate Change, have expressed heightened concerns about the impacts of human activity, especially fossil fuel combustion, on the global climate. In turn, governments and civil society are increasingly focused on limiting the emissions of greenhouse gases (“GHGs”), including emissions of carbon dioxide from the use of oil and natural gas. The EPA has determined that emissions of GHGs, including carbon dioxide and methane, present a danger to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. The EPA has established GHG emission reporting requirements for sources in the oil and gas sector and has also promulgated rules requiring certain large stationary sources of GHGs to obtain preconstruction permits under the CAA and follow “best available control technology” requirements. Although we are not likely to become subject to GHG emissions permitting and best available control technology requirements because none of our facilities are presently major sources of GHG emissions, such requirements could become applicable to our customers and could have an adverse effect on their costs of operations or financial performance, thereby adversely affecting demand for our products and services and our business, financial condition, and results of operations. In December 2015, the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change resulted in nearly 200 countries, including the U.S., coming together to develop the Paris Agreement, which calls for the parties to undertake “ambitious efforts” to limit the average global temperature. Although the agreement did not create any binding obligations for nations to limit their GHG emissions, it did include pledges to voluntarily limit or reduce future emissions. On June 1, 2017, President Trump announced that the U.S. would withdraw from the Paris Agreement and completed the process of withdrawing from the Paris Agreement on November 4, 2020. However, on January 20, 2021, President Biden issued written notification to the United Nations of the United States’ intention to rejoin the Paris Agreement, which became effective on February 19, 2021. Pursuant to its obligations as a signatory to the Paris Agreement, the United States has set a target to reduce its GHG emissions by 50-52% by the year 2030 as compared with 2005 levels and has agreed to provide periodic updates on its progress. In addition, in September 2021, President Biden publicly announced the Global Methane Pledge, a pact that commits its signatories to the collective goal of reducing global methane emissions at least 30% below 2020 levels by 2030, including “all feasible reductions” in the energy sector. Since its formal launch at the United Nations Climate Change Conference (“COP26”), in Glasgow, at least 150 countries have joined the pledge. COP26 then concluded with the finalization of the Glasgow Climate Pact, which stated long-term global goals (including those in the Paris Agreement) to limit the increase in the global average temperature and emphasized reductions in GHG emissions. The impacts of these orders, pledges, agreements, and 9 any legislation, regulation, regulatory initiatives, changes to existing regulation or executive actions promulgated to fulfill the United States’ commitments under the Paris Agreement, COP26, or other international conventions cannot be predicted at this time. While the Biden Administration has pursued executive actions to address climate change, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of GHGs, and many states have already established regional GHG “cap-and-trade” programs, no new comprehensive federal laws regulating the emission of GHGs or directly imposing a price of carbon have been adopted in recent years. However, such legislation has periodically been introduced in the U.S. Congress and may be proposed or adopted in the future. In addition, many state and local leaders have intensified or stated their intent to intensify efforts to support international climate commitments and treaties, in addition to developing programs that are aimed at reducing GHG emissions by means of cap-and-trade programs, carbon taxes, or encouraging the use of renewable energy or alternative low-carbon fuels. The adoption of any new climate change-related legislation or regulation, including any such legislation or regulation that restricts emissions of GHGs from the equipment and operations of our customers or with respect to the oil and natural gas they produce, could adversely affect demand for our products and services. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Moreover, incentives to conserve energy or use alternative energy sources, such as policies designed to increase utilization of zero-emissions or electric vehicles, as a means of addressing climate change could reduce demand for the oil and natural gas produced by our customers and, in turn, could adversely affect demand for our products and services. Finally, most scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that could have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if such effects were to occur, they could have an adverse impact on our operations. Additionally, on March 21, 2022, the SEC issued a proposed rule regarding the enhancement and standardization of mandatory climate-related disclosures for investors. The proposed rule would require registrants to include certain climate-related disclosures in their registration statements and periodic reports, including, but not limited to, information about the registrant’s governance of climate-related risks and relevant risk management processes; climate-related risks that are reasonably likely to have a material impact on the registrant’s business, results of operations, or financial condition and their actual and likely climate-related impacts on the registrant’s business strategy, model, and outlook; climate-related targets, goals and transition plan (if any); certain climate- related financial statement metrics in a note to their audited financial statements; Scope 1 and Scope 2 GHG emissions; and Scope 3 GHG emissions and intensity, if material, or if the registrant has set a GHG emissions reduction target, goal or plan that includes Scope 3 GHG emissions. Although the proposed rule’s ultimate date of effectiveness and the final form and substance of these requirements is not yet known and the ultimate scope and impact on our business is uncertain, compliance with the proposed rule, if finalized, may result in increased legal, accounting and financial compliance costs, make some activities more difficult, time-consuming, and costly, and place strain on our personnel, systems, and resources. Hydraulic Fracturing Our businesses are dependent on hydraulic fracturing and horizontal drilling activities. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process, which involves the injection of water, sand, and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel fuels in fracturing fluids and has issued permitting guidance that applies to such activities. There is considerable uncertainty surrounding regulation of the emissions of methane, which may be released during hydraulic fracturing. In addition to the EPA’s Subpart OOOO regulations and proposed rules discussed above, other federal agencies have promulgated rules regulating methane. On November 30, 2022, the U.S. Bureau 10 of Land Management (the “BLM”) proposed new regulations to reduce the waste of natural gas during the production of oil and gas on federal and tribal lands. The proposed rule would require new and existing operators to submit waste minimization plans with all applications for permits to drill oil wells and includes a number of specific affirmative obligations that operators must take to avoid wasting oil or gas through venting, flaring, and leaks. The proposed rule has received over 3500 public comments, and the final rule may face challenges and legal scrutiny. As a result, future implementation of methane rules by the BLM is uncertain at this time. However, given the long-term trend towards increasing regulation, future federal regulation of methane and other GHG emissions from the oil and gas industry remains a possibility. The EPA has also issued effluent limitation guidelines that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. Also, from time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. It is unclear how any additional federal regulation of hydraulic fracturing activities may affect our operations, but additional regulatory burdens on our customers could ultimately result in decreased demand for our services. Various studies analyzing the potential environmental impacts of hydraulic fracturing have also been performed. For example, the EPA issued a report on the potential impacts of hydraulic fracturing on drinking water resources, which concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. As described elsewhere in this Annual Report, these risks are regulated under various state, federal, and local laws. Some states, counties, and municipalities have implemented, or are considering, increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, disclosure requirements, well construction, and temporary or permanent bans on hydraulic fracturing in certain areas. For example, some states have banned the use of high-volume hydraulic fracturing, and others have adopted regulations that impose new or more stringent permitting, disclosure, disposal, and well construction requirements on hydraulic fracturing operations. Alternatively, some municipalities are, or have considered, zoning and other ordinances, the conditions of which could impose a de facto ban on drilling and/or hydraulic fracturing operations. Further, some states, counties, and municipalities are closely examining water use issues, such as permit and disposal options for processed water, which could have a material adverse impact on our financial condition, prospects, and results of operations if such additional permitting requirements are imposed upon our industry. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could reduce demand for our business by making it more difficult or costly for certain customers to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, the business and operations of our customers could be subject to additional permitting requirements, attendant permitting delays, increased operating and compliance costs and process prohibitions, which could have an adverse effect on our business, financial condition, and results of operations. In light of concerns about seismic activity being triggered by the injection of produced waters into underground wells, certain regulators are also considering additional requirements related to seismic safety for hydraulic fracturing activities. A 2015 U.S. Geological Survey report identified eight states, including Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. Any regulation that restricts the ability of our customers to dispose of produced waters or increases their cost of doing business could cause them to curtail operations, which in turn could decrease demand for our services and have a material adverse effect on our business. 11 National Environmental Policy Act Businesses and operations of our customers that are carried out on federal lands may be subject to the National Environmental Policy Act (“NEPA”), which requires federal agencies, including the Department of the Interior (the “DOI”), to evaluate major agency actions having the potential to significantly impact the human environment. In the course of such evaluations, an agency will evaluate the potential direct, indirect, and cumulative impacts of a proposed project and, if necessary, will prepare a detailed Environmental Impact Statement that must be made available for public review and comment. On July 16, 2020, the Council on Environmental Quality revised NEPA’s implementing regulations in an effort to streamline approvals for projects. On October 6, 2021, the Council on Environmental Quality announced its Phase 1 rule, the first of two planned rules to roll back the 2020 rule, which was finalized on April 20, 2022. The Phase 1 final rule generally restores certain regulatory provisions that were in effect prior to the 2020 rule. To the extent that our customers’ current activities, as well as proposed plans, on federal lands require governmental permits that are subject to the requirements of NEPA, this process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects. Endangered Species Act and Migratory Bird Treaty Act The Endangered Species Act (the “ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species or its habitat. The U.S. Fish and Wildlife Service (the “FWS”) must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. In August 2019, the FWS and National Marine Fisheries Service issued three rules amending implementation of the ESA regulations revising, among other things, the process for listing species and designating critical habitat, which was challenged by a coalition of states and environmental groups. In addition, on December 18, 2020, the FWS amended its regulations governing critical habitat designations, which were also subject to litigation. In June and July 2022, the FWS issued final rules rescinding the regulations defining “habitat” and governing critical habitat exclusions. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”), which makes it illegal to, among other things, hunt, capture, kill, possess, sell, or purchase migratory birds, nests, or eggs without a permit. This prohibition covers most bird species in the U.S. On January 7, 2021, the DOI finalized a rule limiting application of the MBTA; however, the DOI revoked the rule in October 2021 and issued an advance notice of proposed rulemaking seeking comment on the DOI’s plan to develop regulations that authorize incidental take under certain prescribed conditions. The notice of proposed rulemaking is anticipated in March 2023 and is expected to be finalized by the end of 2023. Future implementation of the rules implementing the Endangered Species Act and the MBTA are uncertain. If our customers were to have areas within their business and operations designated as critical or suitable habitat for a protected species, it could decrease demand for our services and have a material adverse effect on our business. There is also increasing interest in nature-related matters beyond protected species, such as general biodiversity, which may similarly require us or our customers to incur costs or take other measures that may adversely impact our business or operations. 12 ITEM 1A. RISK FACTORS We face many challenges and risks in the industry in which we operate. You should carefully consider each of the following risk factors and all of the other information set forth in this Annual Report, including under the section titled “Cautionary Note Regarding Forward-Looking Statements.” The risks and uncertainties described are not the only ones we face. Additional risk factors not presently known to us or which we currently consider immaterial may also adversely affect our business, financial condition, or future results. If any of these risks were actually to occur, our business, financial condition, or results of operations could be materially adversely affected. In that case, the trading price of our common stock could decline, and a stockholder could lose all or part of its investment. RISKS RELATED TO OUR INDUSTRY Our business is cyclical and depends on capital spending and well completions by the onshore oil and natural gas industry, and the level of such activity is volatile. Our business has been, and may continue to be, adversely affected by industry and financial market conditions that are beyond our control. Our business is cyclical, and we depend on our customers’ willingness to make operating and capital expenditures to explore for, develop, and produce oil and natural gas, which, in turn, largely depends on prevailing industry and financial market conditions that are influenced by numerous factors beyond our control, including: • the level of prices, and expectations about future prices, for oil and natural gas; • the domestic and foreign supply of, and demand for, oil and natural gas and related products; • the level of global and domestic oil and natural gas production; • the supply of, and demand for, hydraulic fracturing and other oilfield services and equipment; • governmental regulations, including the policies of governments regarding the exploration for and production and development of their oil and natural gas reserves; • the cost of exploring for, developing, producing, and delivering oil and natural gas; • available pipeline, storage, and other transportation capacity; • worldwide political, military, and economic conditions; • global or national health epidemics or concerns, such as the coronavirus pandemic that began in 2020, which may reduce demand for oil, natural gas, and related products because of reduced global or national economic activity; • lead times associated with acquiring equipment and products and availability of qualified personnel; • the discovery rates of new oil and natural gas reserves; • federal, state, and local regulation of hydraulic fracturing and other oilfield service activities, as well as E&P activities, including public pressure on governmental bodies and regulatory agencies to regulate our industry; • economic and political conditions in oil and natural gas producing countries; • actions of OPEC, its members, and other state-controlled oil companies relating to oil price and production levels, including announcements of potential changes to such levels; • advances in exploration, development, and production technologies or in technologies affecting energy consumption; • activities by non-governmental organizations to restrict the exploration, development, and production of oil and natural gas so as to minimize emissions of carbon dioxide, a GHG; • the price and availability of alternative fuels and energy sources; • global weather conditions and natural disasters, including those related to climate change; and • uncertainty in capital and commodities markets and the ability of oil and natural gas producers to access capital. A decline in oil and natural gas commodity prices may adversely affect the demand for our products and services and the rates we are able to charge. Our business depends, to a significant extent, on the level of unconventional resource development activity and corresponding capital spending of oil and natural gas companies, which are strongly influenced by current and 13 expected oil and natural gas prices. Volatility or weakness in oil and natural gas commodity prices (or the perception that oil and natural gas commodity prices will decrease) affects the spending patterns of our customers and may result in the drilling of fewer new wells or lower production spending on existing wells. Historically, oil and natural gas commodity prices have been extremely volatile. During the past five years ending December 31, 2022, the posted price for West Texas Intermediate (“WTI”) oil has ranged from a low of $(36.98) per barrel in April 2020 to a high of $123.64 per barrel in March 2022, and the Henry Hub spot market price of gas has ranged from a low of $1.33 per MMBtu in September 2020 to a high of $23.86 per MMBtu in February 2021. The theme of capital discipline for E&P operators in the energy industry has led to a significant disconnect between commodity prices and market activity. The average WTI price for 2022 was $94.90, an increase of 39% over 2021 and $55.74 higher than 2020 and $37.91 higher than 2019. Average rig count increased by 51% from 2021 to 2022 and was 67% higher in 2022 than 2020. If prices of oil and natural gas decline or our customers do not increase capex and activity levels, our business, financial condition, results of operations, cash flows, and prospects may be materially and adversely affected. Significant factors that are likely to affect near-term commodity prices include the extent to which members of OPEC and other oil exporting nations, including Russia, continue to reduce oil export prices and increase production; the effect of U.S. energy, monetary, and trade policies; the pace of economic growth in the U.S. and throughout the world, including the potential for macro weakness; geopolitical and economic developments in the U.S. and globally, including conflicts, instability, acts of war or terrorism in oil producing countries or regions, particularly Russia, the Middle East, South America and Africa; changes to energy and EPA policies; and overall North American natural gas supply and demand fundamentals, including the pace at which export capacity grows. For additional information, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview – Industry Trends and Outlook” in Item 7 of Part II of this Annual Report. The products and services we provide are, to a substantial extent, deferrable in the event oil and natural gas companies reduce capital expenditures. As a result, we may experience lower utilization of, and may be unable to increase rates or be forced to lower our rates for, our equipment and services in weak oil and natural gas commodity price environments. Even with supportive oil and natural gas prices, E&P operator activity may not materially increase, as they remain focused on operating within their capital plans. Moreover, any substantial and unexpected drop in commodity prices in the future, even if the drop is relatively short-lived, or expectations of such a drop or of prolonged weak oil and natural gas commodity price environments, could similarly affect our customers’ expectations and capital spending, which could result in a material adverse effect on our business, financial condition, results of operations, cash flows, and prospects. Reduced discovery rates of new oil and natural gas reserves in our market areas as a result of decreased capital spending may also have a negative long-term impact on our business, even in an environment of stronger oil and natural gas prices, to the extent the reduced number of wells for us to service more than offsets increasing completion activity and intensity. 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 or 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. Like others in our industry, in 2021 and 2022 we faced, and we continue to face, cost inflation with both labor and materials, which could offset any price increases for our products and services. 14 Increased attention to climate change and conservation measures may expose us to climate-related transition risks, including evolving climate change legislation, fuel conservation measures, technological advances and negative shift in market perception towards the oil and natural gas industry, which could result in reduced demand for oil and natural gas. Increased attention to climate change from governmental and regulatory bodies, investors, consumers, industry and other stakeholders, changes in consumer behavior and related demand for alternatives to oil and natural gas, societal expectations on companies to address climate change, preferences and attitudes with respect to the generation and consumption of energy, the use of hydrocarbons, and the use of products manufactured with, or powered by, hydrocarbons, may result in the enactment of climate change-related regulations, policies and initiatives (at the government, regulator, corporate and/or investor community levels), including alternative energy requirements, new fuel consumption standards, energy conservation and emissions reductions measures and responsible energy development, technological advances with respect to the generation, transmission, storage and consumption of energy, and increased availability and competitiveness of alternative energy sources (such as wind, solar geothermal, tidal, fuel cells, and biofuels). These developments could reduce demand for oil and natural gas and therefore our products and services, which would lead to a reduction in our revenues and have a material adverse effect on our business, financial condition, results of operations, cash flows, and prospects. In addition, the enactment of climate change-related regulations, policies and initiatives (at the government, corporate and/or investor community levels) may in the future result in increases in our compliance costs and other operating costs and have other adverse effects (e.g., greater potential for governmental investigations or litigation). For further discussion regarding the risks posed to us by climate change-related regulations, policies and initiatives and by negative public perception of the oil and gas industry, see the discussions below in “Negative public perception of the oil and gas industry could adversely affect our operations and our ability raise debt and equity capital” and “Existing or future laws and regulations related to GHGs and climate change could have a negative impact on our business and may result in additional compliance obligations with respect to the release, capture, and use of GHGs that could have a material adverse effect on our business, results of operations, prospects, and financial condition.” Negative public perception of the oil and gas industry could adversely affect our operations and our ability to raise debt and equity capital. Opposition toward the oil and natural gas industry has been growing globally and is particularly pronounced in the United States. Companies in the oil and natural gas industry are often the target of activist efforts from both individuals and non-governmental organizations regarding safety, human rights, climate change, environmental matters, sustainability, and business practices. Anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain operations such as drilling and development. Any such activism against oil and natural gas exploration and development may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. In addition, some parties have initiated public nuisance claims under federal or state common law against certain companies involved in the production of oil and natural gas, or claims alleging that the companies have been aware of the adverse effects of climate change for some time but failed to adequately disclose such impacts to their investors or customer. Although our business is not a party to any such litigation, we could be named in actions making similar allegations, which could lead to costs and materially impact our financial condition in an adverse way. Negative perceptions regarding our industry and reputational risks may also in the future adversely affect our ability to successfully carry out our business strategy by adversely affecting our access to capital. Certain segments of the investor community have developed negative sentiment towards investing in our industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. Parties concerned about the potential effects of climate change have directed their attention at sources of financing for energy companies, which has resulted in certain financial institutions, funds and other capital providers restricting or eliminating their investment in oil and natural gas activities. In addition, some 15 investors, including investment advisors and certain sovereign wealth funds, pension funds, university endowments, and family foundations, have stated policies to disinvest in the oil and gas sector based on their social and environmental considerations. Further, certain investment banks and asset managers based both domestically and internationally have announced that they are adopting climate change guidelines for their banking and investing activities. Certain other stakeholders have also pressured commercial and investment banks to stop financing oil and gas production and related infrastructure projects. Such developments, including environmental activism, investment policies and initiatives, and related litigation aimed at limiting climate change and reducing air pollution, could result in downward pressure on the stock prices of oil and gas companies, including ours. These developments may also potentially result in a reduction of available capital funding for potential development projects, impacting our future financial results. Increased scrutiny of sustainability matters could have an adverse effect on our business and damage our reputation. In recent years, companies across all industries are facing increasing scrutiny from a variety of stakeholders, including investor advocacy groups, proxy advisory firms, certain institutional investors and lenders, investment funds and other influential investors and rating agencies, related to their environmental, social and governance (“ESG”) and sustainability practices. If we do not adapt to or comply with investor or other stakeholder expectations and standards on ESG matters (or meet sustainability goals and targets that we have set) as they continue to evolve, or if we are perceived to have not responded appropriately or quickly enough to growing concern for ESG and sustainability issues, regardless of whether there is a regulatory or legal requirement to do so, we may suffer from reputational damage and our business, financial condition and/or stock price could be materially and adversely affected. 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 could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital. RISKS RELATED TO OUR INDEBTEDNESS Our substantial debt obligations could have significant adverse consequences on our business and future prospects. As of February 1, 2023, we had $300.0 million of 13.000% Senior Secured Notes due 2028 (the “2028 Notes”) outstanding, and we had $72.0 million of borrowings under the ABL Credit Facility (as defined and described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources” in Item 7 of Part II of this Annual Report) outstanding. Subject to the restrictions in the ABL Credit Agreement (as defined and described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources” in Item 7 of Part II of this Annual Report) and the indenture governing the 2028 Notes, we may incur substantial additional indebtedness (including secured indebtedness) in the future. Our current or future level of indebtedness could have significant adverse consequences on our business and future prospects, including in the following ways: • requiring us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities; • limiting management’s discretion in operating our business and our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; • increasing our vulnerability to downturns and adverse developments in our business and the economy generally; • limiting our ability to access the capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures, or acquisitions or to refinance existing indebtedness; • placing us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size or less restrictive terms governing their indebtedness; and 16 • making it more difficult for us to satisfy our obligations under our debt instruments and increase the risk that we may default on our debt obligations. Additionally, borrowings under the ABL Credit Facility bear interest at variable rates exposing us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remains the same, and our net income and cash available to finance our operations and other business activities would decrease. We may not be able to generate sufficient cash to service all of our indebtedness. Our ability to make scheduled payments with respect to our indebtedness depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business, and other factors beyond our control. If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to sell assets, seek additional capital, or restructure or refinance indebtedness. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations. For example, we may not be able to consummate dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. Also, our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. In addition, any debt restructuring transactions may involve the issuance of additional equity or convertible debt securities that could result in material dilution to our stockholders, and these securities could have rights superior to holders of our common stock and could contain covenants that will restrict our operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. If we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, and interest on our indebtedness, we could be in default under the terms of the agreements governing such indebtedness. An event of default, if not waived, could result in acceleration of the indebtedness outstanding under the applicable agreement and an event of default with respect to, and an acceleration of, the indebtedness outstanding under any other debt agreements to which we are a party. Any such accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required payments. In addition, any failure to make payments on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. Restrictions in our debt agreements could limit our growth and our ability to engage in certain activities. The ABL Credit Facility and the indenture governing our 2028 Notes have, and future financing agreements could have, restrictive covenants that could restrict our ability to finance future operations or capital needs or to expand or pursue our business activities. For example, our debt agreements contain restrictive covenants that limit our ability to, among other things: • incur additional indebtedness and guarantee indebtedness; • pay dividends or make other distributions or repurchase or redeem our capital stock; • transfer or sell assets; • make loans and investments; • incur liens; • enter into agreements that restrict dividends or other payments from any non-guarantor restricted subsidiaries to us; • consolidate, merge, or sell all or substantially all of our assets; • prepay, redeem, or repurchase certain debt; • issue certain preferred stock or similar equity securities; • make certain acquisitions and investments; • engage in transactions with affiliates; and • create unrestricted subsidiaries. 17 The restrictions in our debt agreements could also impact our ability to obtain capital to withstand a downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our debt arrangements may impose on us. A breach of any covenant in our debt agreements will result in a default under the applicable agreement and an event of default under such agreement if there is no grace period or if such default is not cured during any applicable grace period. An event of default, if not waived, could result in acceleration of the indebtedness outstanding under the applicable agreement and an event of default with respect to, and an acceleration of, the indebtedness outstanding under any other debt agreements to which we are a party. Any such accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us. COMPETITION AND MARKET RISKS We may be unable to maintain existing prices or implement price increases on our products and services. We periodically seek to increase the prices on our products and services to offset rising costs and to generate higher returns for our stockholders. However, we operate in a very competitive industry and as a result, we are not always successful in raising or maintaining our existing prices. Volatility in oil and natural gas prices can impact our customers’ activity levels, and current energy prices are important contributors to cash flow for our customers and their actual or perceived ability to fund exploration and development activities, which may limit our ability to increase or maintain prices. Additionally, during periods of increased market demand, a significant amount of new service capacity, including new well service rigs, wireline units, and coiled tubing units, may enter the market, which also puts pressure on the pricing of our services and limits our ability to increase prices. Even when we are able to increase our prices, we may not be able to do so at a rate that is sufficient to offset rising costs. In periods of high demand for oilfield services, a tighter labor market may result in higher labor costs. During such periods, our labor costs could increase at a greater rate than our ability to raise prices for our services. Also, we may not be able to successfully increase prices without adversely affecting our activity levels. The inability to maintain our pricing and to increase our pricing as costs increase could have a material adverse effect on our business, financial position, results of operations, and cash flows. Intense competition in the markets for our dissolvable plug products may lead to pricing pressures, reduced sales, or reduced market share. The oil and natural gas industry is intensely competitive and has been characterized by price erosion for new technologies as additional competing products enter the market. In 2020, we experienced a decline in the pricing and profitability of our dissolvable plug products and, to a lesser extent, our composite plug products due to the impacts of the coronavirus pandemic on the oil and natural gas industry. Pricing toward the end of 2021 and throughout 2022 mostly stabilized; however, any future price declines, future lack of availability of materials, or future increases in prices in materials may harm our business. We compete with major domestic and international oilfield services companies, many of which have greater market recognition and substantially greater financial, technical, marketing, distribution, and other resources than we do. We have experienced pricing declines in certain of our more mature proprietary product lines, primarily due to competitive conditions. Likewise, our customers may seek pricing declines more precipitously than our ability to reduce costs, leaving us unable to achieve or maintain pricing to our customers at a level sufficient to cover our costs. We are continuing to work on reducing manufacturing costs of our products, as well as introducing new and differentiated technology to improve profitability, however, there can be no assurance that we will be able to do so in the future. If the amounts we are able to charge customers for our dissolvable plug products decline further or are insufficient to cover our costs, that could have a material adverse effect on our financial condition, results of operations, and cash flows. 18 Our current and potential competitors may have longer operating histories, significantly greater financial or technical resources, and greater name recognition than we do. The oilfield services industry is highly competitive and fragmented and includes several large companies that compete in many of the markets we serve, as well as numerous small companies that compete with us on a local basis. The oilfield services industry competes primarily on a regional basis, and the intensity of competition may vary significantly from region to region at any particular time. We believe the principal competitive factors in the market areas we serve include price, equipment quality, supply chains, balance sheet strength and financial condition, product and service quality, safety record, availability of crews and equipment, and technical proficiency. Many of our existing and potential competitors have substantially greater financial, technical, manufacturing, and other resources than we do. The greater size of many of our competitors provides them with cost advantages as a result of their economies of scale and their ability to obtain volume discounts and purchase raw materials at lower prices. As a result, such competitors may have stronger bargaining power with their suppliers and have an advantage over us in pricing as well as securing a sufficient supply of raw materials during times of shortage. Many of our competitors also have better brand name recognition, stronger presence in more geographic markets, more established distribution networks, larger customer bases, more in-depth knowledge of the target markets, and the ability to provide a much broader array of products and services. Some of our competitors may also be able to devote greater resources to the research and development, promotion, and sale of their products and better withstand the evolving industry standards and changes in market conditions as compared to us. Our operations may be adversely affected if our competitors introduce new products or services with better features, performance, prices, or other characteristics than our products and services or expand into service areas where we operate. Our operations may also be adversely affected if our competitors are able to respond more quickly to new or emerging technologies and services and changes in customer requirements. Competitive pressures could reduce our market share or require us to reduce the price of our services and products, particularly during industry downturns, either of which would harm our business and operating results. Significant increases in overall market capacity have also caused active price competition and led to lower pricing and utilization levels for our services and products. The competitive environment has intensified since the industry downturn that began in late 2014, which caused an oversupply of, and reduced demand for, oilfield services, and we have seen substantial reductions in the prices we can charge for our services and products. Any significant future increase in overall market capacity for completion services may adversely affect our business, financial condition, and results of operations. OPERATIONAL RISKS Our operations are subject to conditions inherent in the oilfield services industry. Conditions inherent in the oil and natural gas industry can cause personal injury or loss of life, disruption or suspension in operations, damage to geological formations, damage to facilities, substantial revenue loss, business interruption, and damage to, or destruction of, property, equipment, and the environment. Such risks may include, but are not limited to: • equipment defects; • liabilities arising from accidents or damage involving our fleet of trucks and other equipment; • explosions and uncontrollable flows of gas or well fluids; • unusual or unexpected geological formations or pressures and industrial accidents; • blowouts; • fires; • cratering; • loss of well control; • collapse of the borehole; and • damaged or lost equipment. Defects or other performance problems in the products that we sell or services that we offer could result in our customers seeking damages from us for losses associated with these defects or other performance problems. In 19 addition, our services could become a source of spills or release of fluids, including chemicals used during hydraulic fracturing activities, at the site where such services are performed, or could result in the discharge of such fluids into underground formations that were not targeted for fracturing or well completion activities, such as potable aquifers, or at third-party properties. These risks could expose us to substantial liability for personal injury, wrongful death, property damage, loss of oil and natural gas production, pollution, and other environmental damages and could result in a variety of claims, losses, and remedial obligations that could have an adverse effect on our business and results of operations. The existence, frequency, and severity of such incidents could affect operating costs, insurability, and relationships with customers, employees, and regulators. In particular, our customers may elect not to purchase our services if they view our safety record as unacceptable or otherwise experience material defects in our products or performance problems, which could cause us to lose substantial revenue. In addition, any litigation or claim, even if fully indemnified or insured, could negatively affect our reputation with our customers and the public, which could cause us to lose customers and substantial revenue, make it more difficult for us to compete effectively, or obtain adequate insurance in the future. Our assets require capital for maintenance, upgrades, and refurbishment, and we may require capital expenditures for new equipment. Our equipment requires capital investment in maintenance, upgrades, and refurbishment to maintain their competitiveness. For the years ended December 31, 2022 and 2021, we spent approximately $13.6 million and $7.4 million, respectively, on capital expenditures related to maintenance, and we expect to spend approximately $20 million to $30 million on capital expenditures related to maintenance in 2023. Our equipment typically does not generate revenue while it is undergoing maintenance, upgrades, or refurbishment. Any maintenance, upgrade, or refurbishment project for our assets could increase our indebtedness or reduce cash available for other opportunities. Further, such projects may require proportionally greater capital investments as a percentage of total asset value, which may make such projects difficult to finance on acceptable terms. To the extent we are unable to fund such projects, we may have less equipment available for service or our equipment may not be attractive to potential or current customers. Additionally, competition or advances in technology within our industry may require us to update our products and services. Such demands on our capital or reductions in demand and the increase in cost to maintain labor necessary for such maintenance and improvement, in each case, could have a material adverse effect on our business, liquidity position, financial condition, prospects, and results of operations and may increase costs. In addition, although such projects may require material capital expenditures, there is no assurance that they will generate a positive return. Seasonal and adverse weather conditions and the physical risks arising from climate change may have a negative impact on our business and result of operations, including by adversely affecting demand for our products and services. Weather can have a significant impact on demand for our services and products as consumption of energy is seasonal, and any variation from normal weather patterns or cooler or warmer summers and winters can have a significant impact on demand. In addition, adverse weather conditions, such as hurricanes, tropical storms, and severe cold weather, may interrupt or curtail our operations or our customers’ operations, cause supply disruptions, and damage our equipment and facilities, which may or may not be insured. In addition, most scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that could have significant physical effects, such as increased frequency and severity of storms, droughts, floods, and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for oil and natural gas, which, in turn, could also reduce the demand for our products and services; cause us to incur significant costs in preparing for or responding to the effects of climatic events themselves, which may not be fully insured; or cause an adverse impact on our operations. Our ability to mitigate the adverse physical impacts of climate change depends in part upon our disaster preparedness and response and business continuity planning. During the winter months (portions of the first and fourth quarters) and periods of heavy snow, ice, or rain, particularly in the northeastern U.S., Michigan, North Dakota, Wyoming, and western Canada, our customers may delay operations, or we may not be able to operate or move our equipment between locations. Also, during the spring thaw, which normally starts in late March and continues through June, some areas, primarily in western Canada, impose transportation restrictions to prevent damage caused by the spring thaw. For the years ended December 31, 2022 and 2021, we generated approximately 0.3% and 0.6%, respectively, of our revenue from our operations in western 20 Canada. Lastly, throughout the year heavy rains adversely affect activity levels because well locations and dirt access roads can become impassible in wet conditions. In addition, we typically have experienced a pause by our customers around the holiday season in the fourth quarter, which may be compounded as our customers exhaust their annual capital spending budgets towards year end. RISKS RELATED TO OUR CUSTOMERS AND SUPPLIERS If we are unable to accurately predict customer demand or if customers cancel their orders on short notice, we may hold excess or obsolete inventory, which would reduce gross margins. Conversely, insufficient inventory would result in lost revenue opportunities and potentially loss of market share and damaged customer relationships. We often place orders with our suppliers based on forecasts of customer demand. Anticipating customer demand is difficult because our customers face unpredictable demand for their own products and are increasingly focused on cash preservation and tighter inventory management. Our forecasts of customer demand are based on multiple assumptions, each of which may introduce errors into the forecasts. If we overestimate customer demand, we may allocate resources to the purchase of material or manufactured products that we may not be able to sell when we expect to, if at all. As a result, we would hold excess or obsolete inventory, which would reduce gross margin and adversely affect financial results. Conversely, if we underestimate customer demand or if insufficient manufacturing capacity is available, we would miss revenue opportunities and potentially lose market share and damage our customer relationships. In addition, any future significant cancellations or deferrals of orders or the return of previously sold products could materially and adversely affect profit margins, increase inventory obsolescence, and restrict our ability to fund our operations. We are exposed to the credit risk of our customers, and the deterioration of the financial condition of our customers could adversely affect our financial results. We are subject to the risk of loss resulting from nonpayment or nonperformance by our customers, many of whose operations are concentrated solely in the domestic and Canadian E&P industry, which, as described above, is subject to volatility and, therefore, credit risk. Our credit procedures and policies may not be adequate to fully reduce customer credit risk. If we are unable to adequately assess the creditworthiness of existing or future customers or unanticipated deterioration in their creditworthiness, any resulting increase in nonpayment or nonperformance by them and our inability to re-market or otherwise use our equipment could have a material adverse effect on our business, financial condition, prospects, and/or results of operations. In the course of our business, we hold accounts receivable from our customers. In the event of the financial distress or bankruptcy of a customer, we could lose all or a portion of such outstanding accounts receivable associated with that customer. Further, if a customer was to enter into bankruptcy, it could also result in the cancellation of all or a portion of our service contracts with such customer at significant expense or loss of expected revenues to us. In addition, during times when the oil or natural gas markets weaken, our customers are more likely to experience financial difficulties, including being unable to access debt or equity financing, which could result in a reduction in our customers’ spending for our products and services. We are dependent on customers in a single industry. The loss of one or more significant customers could adversely affect our financial condition, prospects, and results of operations. Our customers are engaged in the oil and natural gas E&P business, which has been historically volatile. For the year ended December 31, 2022, our five largest customers collectively accounted for approximately 21% of total revenues. If we were to lose several key alliances over a relatively short period of time or if one of our largest customers fails to pay or delays in paying a significant amount of our outstanding receivables, we could experience an adverse impact on our business, financial condition, results of operations, cash flows, and prospects. Additionally, the E&P industry is characterized by frequent consolidation activity. Changes in ownership of our customers may result in the loss of, or reduction in, business from those customers, which could materially and adversely affect our business, financial condition, results of operations, and prospects. 21 Certain of our product lines are subject to the risk of supplier concentration, and certain of our product lines are subject to exclusive distribution arrangements, which we may not be able to maintain. Certain of the product lines depend on a limited number of third-party suppliers and vendors. As a result of this concentration in some supply chains, our business and operations could be negatively affected if certain key suppliers were to experience significant disruptions affecting the price, quality, availability, or timely delivery of their products. The partial or complete loss of any one of those key suppliers, or a significant adverse change in the relationship with any such suppliers, through consolidation or otherwise, may limit our ability to manufacture and sell certain of our product lines. In addition, we have arrangements with certain technology companies and manufacturers that give us exclusive distribution rights to certain product offerings. In some cases, we are, or may in the future will be, required to meet certain minimum volume or other requirements in order to retain our arrangement. If any of these companies or manufacturers terminate our right to sell some or all of their products, modify or terminate our exclusive distribution arrangement, or change the applicable terms and conditions of sale, our business and results of operations could be adversely affected. REGULATORY, COMPLIANCE, AND LEGAL RISKS 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. We may be subject to claims for personal injury and property damage or other litigation, which could materially adversely affect our financial condition, prospects, and results of operations. Our services are subject to inherent risks that can cause personal injury or loss of life, damage to or destruction of property, equipment, or the environment, or the suspension of our operations. As the wells we service continue to become more complex, our exposure to such inherent risks becomes greater as downhole risks increase exponentially with an increase in complexity and lateral length. Our operations are also exposed to risks of labor organizing and risks of claims for alleged employment-related liabilities, including risks of claims related to alleged wrongful termination or discrimination, wage payment practices, retaliation claims, and other human resource related matters. Litigation arising from operations where our facilities are located, or our services are provided, may cause us to be named as a defendant in lawsuits asserting potentially large claims, including claims for exemplary damages. For example, transportation of heavy equipment creates the potential for our trucks to become involved in roadway accidents, which in turn could result in personal injury or property damages lawsuits being filed against us. We maintain what we believe is customary and reasonable insurance to protect our business against most potential losses, but such insurance may not be adequate to cover our liabilities, especially as the inherent risks in our operations increase with increasing well complexity, and we are not fully insured against all risks, including alleged employment-related liabilities. Further, our insurance has deductibles or self-insured retentions and contains certain coverage exclusions. The current trend in the insurance industry is towards larger deductibles and self- insured retentions. In addition, insurance may not be available in the future at rates that we consider reasonable and commercially justifiable, compelling us to have larger deductibles or self-insured retentions to effectively manage expenses. As a result, we could become subject to material uninsured liabilities or situations where we have high 22 deductibles or self-insured retentions that expose us to liabilities that could have a material adverse effect on our business, financial condition, prospects, or results of operations. In recent years, oilfield services companies have been the subject of a significant volume of wage and hour- related litigation, including claims brought under the Fair Labor Standards Act (“FLSA”), in which employee pay practices have been challenged. We have been named as defendants in these lawsuits, and we do not maintain insurance for alleged wage and hour-related litigation. Some of these cases remain outstanding and are in various states of negotiation and/or litigation, and the results or costs of any such cases may have an adverse effect on our business, operating results, and financial condition. The frequency and significance of wage- or other employment- related claims may affect expenses, costs, and relationships with employees and regulators. Additionally, we could become subject to material uninsured liabilities that could have a material adverse effect on our business, financial condition, prospects, or results of operations. Delays or restrictions in obtaining, or inability to obtain or renew, permits or authorizations by our customers for their operations or by us for our operations could impair our business. In most states, our operations and the operations of our customers require permits or authorizations from one or more governmental agencies or other third parties to perform drilling and completion and production activities, including hydraulic fracturing. Such permits or approvals are typically required by state agencies, but federal and local governmental permits may also be required. We are also required to obtain federal, state, local, and/or third- party permits and authorizations in some jurisdictions in connection with our wireline services and trucking operations. The requirements for permits or authorizations vary depending on the location where the associated activities will be conducted. As with most permitting and authorization processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit or approval to be issued, and the conditions which may be imposed in connection with the granting of the permit. Over the past several years, parts of the country have experienced extreme drought conditions. As a result of these conditions, some rural water districts have begun to impose restrictions on water use and may require permits for water used in drilling and completion activities. In addition, some of our customers’ drilling and completion activities may take place on federal land or Native American lands, requiring leases and other approvals from the federal government or Native American tribes to conduct such drilling and completion activities. Permitting, authorization, or renewal delays, the inability to obtain new permits, or the revocation of current permits could cause a loss of revenue and potentially have a materially adverse effect on our business, financial condition, prospects, or results of operations. We are subject to federal, state, and local laws and regulations regarding issues of health, safety, and protection of the environment. Under these laws and regulations, we may become liable for penalties, damages, or costs of remediation or other corrective measures. Any changes in laws or government regulations could increase our costs of doing business. Our operations are subject to stringent federal, state, local, and tribal laws and regulations relating to, among other things, protection of natural resources, clean air and drinking water, wetlands, endangered species, GHGs, air pollution, the environment, occupational health and safety, chemical use and storage, waste management, waste disposal, and transportation of waste and other hazardous and nonhazardous materials. Our operations involve risks of environmental liability, including leakage from an operator’s casing during our operations or accidental spills of hazardous materials onto or into surface or subsurface soils, surface water, or groundwater. Some environmental laws and regulations may impose strict liability, joint and several liability, or both. In some situations, we could be exposed to liability as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, third parties without regard to whether we caused or contributed to the conditions. Additionally, environmental concerns, including clean air, drinking water contamination, and seismic activity, have prompted investigations that could lead to the enactment of regulations, limitations, restrictions, or moratoria that could potentially have a material adverse impact on our business. Actions arising under these laws and regulations could result in the shutdown of our operations, fines and penalties (administrative, civil, or criminal), revocations of permits to conduct business, expenditures for remediation or other corrective measures, and/or claims for liability for property damage, exposure to hazardous materials, exposure to hazardous waste, nuisance, or personal injuries. Sanctions for noncompliance with applicable environmental laws and regulations may also include the assessment of 23 administrative, civil, or criminal penalties, revocation of permits and temporary or permanent cessation of operations in a particular location, and issuance of corrective action orders. Such claims or sanctions and related costs could cause us to incur substantial costs or losses and could have a material adverse effect on our business, financial condition, prospects, and results of operations. Additionally, an increase in regulatory requirements or limitations, restrictions, or moratoria on oil and natural gas exploration and completion activities at a federal, state, or local level could significantly delay or interrupt our operations, limit the amount of work we can perform, increase our costs of compliance, or increase the cost of our services, thereby possibly having a material adverse impact on our financial condition. If we do not perform our operations in accordance with government, industry, customer, or our own stringent occupational safety, health, and environmental standards, we could lose business from our customers, many of whom have an increased focus on environmental and safety issues. We are subject to the oversight of the EPA, the U.S. Department of Transportation (the “DOT”), the U.S. Nuclear Regulation Commission, Bureau of Alcohol, Tobacco, Firearms and Explosives, OSHA, and state regulatory agencies that regulate operations to prevent air, soil, and water pollution or to protect against the effects of ionizing radiation. The energy extraction sector is one of the sectors designated for increased enforcement by the EPA, which will continue to regulate our industry in the years to come, potentially resulting in additional regulations that could have a material adverse impact on our business, prospects, or financial condition. The EPA regulates air emissions from all engines, including off-road diesel engines that are used by us to power equipment in the field under the CAA Tier 4 emission standards (the “Tier 4” standards). The Tier 4 standards require substantial reductions in emissions of particulate matter and nitrous oxide from off-road diesel engines. Such emission reductions can be achieved through the use of appropriate control technologies. Under these U.S. emission control regulations, we could be limited in the number of certain off-road diesel engines we can purchase if we are unable to find a sufficient number of Tier 4-compliant engines from manufacturers. Further, these emission control regulations could result in increased capital and operating costs. Changes in environmental laws and regulations could lead to material increases in our costs, and liability exposure, for future environmental compliance and remediation. Additionally, if we expand the size or scope of our operations, we could be subject to regulatory requirements that are more stringent than the requirements under which we are currently allowed to operate or require additional authorizations to continue operations. Compliance with this additional regulatory burden could increase our operating or other costs. Federal, state, and local legislative and regulatory initiatives relating to hydraulic fracturing could prohibit, restrict, or limit hydraulic fracturing operations, or increase our operating costs. Our businesses are dependent on hydraulic fracturing and horizontal drilling activities. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process, which involves the injection of water, sand, and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, federal agencies have asserted regulatory authority over certain aspects of the process. For more information on existing regulations and regulatory initiatives relating to hydraulic fracturing, see “Regulatory Matters – Hydraulic Fracturing” in Item 1 of Part I of this Annual Report. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could reduce demand for our business by making it more difficult or costly for certain customers to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, the business and operations of our customers could be subject to additional permitting requirements, and also to attendant permitting delays, increased operating and compliance costs, and process prohibitions, which could have an adverse effect on our business, financial condition, and results of operations. 24 Existing or future laws and regulations related to GHGs and climate change could have a negative impact on our business and may result in additional compliance obligations with respect to the release, capture, and use of GHGs that could have a material adverse effect on our business, results of operations, prospects, and financial condition. Changes in environmental requirements related to GHG emissions and climate change may negatively impact demand for our products and services. For example, oil and natural gas E&P may decline as a result of environmental requirements, including land use policies responsive to environmental concerns (e.g., numerous cities, including San Francisco, CA, and Seattle, WA, have banned the use of natural gas in new construction, and other cities, including New York, NY, are considering similar initiatives). Federal, state, and local agencies have been evaluating climate- related legislation and other regulatory initiatives that would restrict emissions of GHGs in areas in which we conduct business. Because our business depends on the level of activity in the oil and natural gas industry, existing or future laws and regulations related to GHGs and climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on our business if such laws or regulations reduce demand for oil and natural gas. Likewise, such restrictions may result in additional compliance obligations with respect to the release, capture, sequestration, and use of GHGs that could have a material adverse effect on our business, results of operations, prospects, and financial condition. Additionally, the SEC issued a proposed rule in March 2022 that would mandate extensive disclosure of climate-related data, risks, and opportunities, including financial impacts, physical and transition risks, related governance and strategy, and GHG emissions, for certain public companies. We cannot predict the costs of implementation or any potential adverse impacts resulting from the rulemaking. However, to the extent this rulemaking is finalized as proposed, we could incur increased costs relating to the assessment and disclosure of climate-related risks. We may also face increased litigation risks related to disclosures made pursuant to the rule if finalized as proposed. Studies by either state or federal agencies demonstrating a correlation between earthquakes and oil and natural gas activities could result in increased regulatory and operational burdens. In light of concerns about seismic activity being triggered by the injection of produced waters into underground wells, certain regulators are also considering additional requirements related to seismic safety for hydraulic fracturing activities. A 2015 U.S. Geological Survey report identified eight states, including Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. Any regulation that restricts the ability of our customers to dispose of produced waters or increases their cost of doing business could cause them to curtail operation, which in turn could decrease demand for our products and services and have a material adverse effect on our business. We are subject to complex U.S. and foreign laws and regulations governing anti-corruption and export controls and economic sanctions. The U.S. Foreign Corrupt Practices Act (the “FCPA”), the U.K. Bribery Act (“UKBA”), Canada’s Corruption of Foreign Public Officials Act (the “CFPOA”), and similar anti-bribery and anti-corruption laws generally prohibit companies and their intermediaries from making improper payments or improperly providing anything of value for the purpose of obtaining or retaining business. We operate and make sales in parts of the world that may be viewed as higher risk for corruption or may have experienced some corruption in the past, and in some instances, strict compliance with the FCPA, UKBA, CFPOA, and similar anti-bribery laws may conflict with local practices. We are also subject to export control and economic sanctions laws and regulations, including those implemented by the U.S. Office of Foreign Assets Control, the U.S. Department of State, the U.S. Department of Commerce, the European Union and its member states, Her Majesty’s Treasury of the United Kingdom, and other relevant sanctions authorities. These measures can prohibit or restrict transactions and dealings with certain designated persons and in certain countries in which we conduct business. Despite efforts to ensure compliance, there can be no assurance that our directors, officers, employees, agents, and third-party intermediaries will comply with such laws and regulations. We can be held liable for violations under such laws and regulations either due to our acts or omissions or due to the acts or omissions of others, including intermediaries working on our behalf. 25 If we fail to comply with applicable laws and regulations, including those referred to above, we may be subject to criminal and civil penalties or other sanctions, which could harm our reputation and have a material adverse impact on our business, financial condition, results of operations, and prospects. Any investigation of any actual or alleged violations of such laws could also harm our reputation or have an adverse impact on our business, financial condition, results of operations, and prospects. Additionally, we could face other third-party claims by agents, stockholders, debt holders, or other interest holders or constituents of our company. Our customers in relevant jurisdictions could seek to impose penalties or take other actions adverse to our interests, and we may be required to dedicate significant time and resources to investigate and resolve allegations of misconduct, regardless of the merit of such allegations. Furthermore, compliance with this additional regulatory burden could increase our operating or other costs. Changes in transportation regulations may increase our costs and negatively impact our results of operations. We are subject to various transportation regulations including as a motor carrier by the DOT and by various federal, state, and tribal agencies, whose regulations include certain permit requirements of highway and safety authorities. These regulatory authorities exercise broad powers over our trucking operations, generally governing such matters as the authorization to engage in motor carrier operations, safety, equipment testing, driver requirements and specifications, and insurance requirements. Certain motor vehicle operators are required to register with the DOT. This registration requires an acceptable operating record. The DOT periodically conducts compliance reviews and may revoke registration privileges based on certain safety performance criteria, and a revocation could result in a suspension of operations. Since 2010, the DOT has pursued its Compliance, Safety, Accountability (“CSA”) program in an effort to improve commercial truck and bus safety. A component of CSA is the Safety Measurement System (“SMS”), which analyzes all safety violations recorded by federal and state law enforcement personnel to determine a carrier’s safety performance. The SMS is intended to allow the DOT to identify carriers with safety issues and intervene to address those problems. The trucking industry is subject to possible regulatory and legislative changes that may impact our operations, such as changes in fuel emissions limits, hours of service regulations that govern the amount of time a driver may drive or work in any specific period, and limits on vehicle weight and size. For example, in December 2016, the DOT finalized minimum training standards for new drivers seeking a commercial driver’s license, and effective December 2017, the FMCSA has mandated electronic logging devices in all interstate commercial trucks. As the federal government continues to develop and propose regulations relating to fuel quality, engine efficiency, and GHG emissions, we may experience an increase in costs related to truck purchases and maintenance, impairment of equipment productivity, a decrease in the residual value of vehicles, unpredictable fluctuations in fuel prices, and an increase in operating expenses. Increased truck traffic may contribute to deteriorating road conditions in some areas where our operations are performed. Our operations, including routing and weight restrictions, could be affected by road construction, road repairs, detours, and state and local regulations and ordinances restricting access to certain roads. Proposals to increase federal, state, or local taxes, including taxes on motor fuels, are also made from time to time, and any such increase would increase our operating costs. Also, state and local regulation of permitted routes and times on specific roadways could adversely affect our operations. We cannot predict whether, or in what form, any legislative or regulatory changes or municipal ordinances applicable to our logistics operations will be enacted and to what extent any such legislation or regulations could increase our costs or otherwise adversely affect our business or operations. RISKS RELATED TO TECHNOLOGY Our success may be affected by the use and protection of our proprietary technology as well as our ability to enter into license agreements. There are limitations to our intellectual property rights and, thus, our right to exclude others from the use of our proprietary technology. Our success may be affected by our development and implementation of new product designs and improvements and by our ability to protect, obtain, and maintain intellectual property assets related to these developments. We rely on a combination of patents and trade secret laws to establish and protect this proprietary 26 technology. We have received patents and have filed patent applications with respect to certain aspects of our technology, and we generally rely on patent protection with respect to our proprietary technology, as well as a combination of trade secrets and copyright law, employee and third-party non-disclosure agreements, and other protective measures to protect intellectual property rights pertaining to our products and technologies. In addition, we are a party to and rely on several arrangements with third parties, which give us exclusive distribution rights to certain product offerings with desirable intellectual property assets, and we may enter into similar arrangements in the future. Such measures may not provide meaningful protection of our trade secrets, know-how, or other intellectual property in the event of any unauthorized use, misappropriation, or disclosure. We cannot ensure that competitors will not infringe upon, misappropriate, violate, or challenge our intellectual property rights in the future. Additionally, we cannot ensure that our intellectual property rights will deter or prevent competitors from creating similar purpose products for our customers. If we are not able to adequately protect or enforce our intellectual property rights, such intellectual property rights may not provide significant value to our business, results of operations, or financial condition. Moreover, our rights in our confidential information, trade secrets, and confidential know-how will not prevent third parties from independently developing similar technologies or duplicating such technologies. Publicly available information (e.g., information in issued patents, published patent applications, and scientific literature) can be used by third parties to independently develop technology, and we cannot provide assurance that this independently-developed technology will not be equivalent or superior to our proprietary technology. In addition, while we have patented some of our key technologies, we do not patent all of our proprietary technology, even when regarded as patentable. The process of seeking patent protection can be long and expensive. There can be no assurance that patents will be issued from currently pending or future applications or that, if patents are issued, they will be of sufficient scope or strength to provide meaningful protection or any commercial advantage to us. Further, with respect to exclusive third-party arrangements, these arrangements could be terminated, which would result in our inability to provide the services and/or products covered by such arrangements. We may be adversely affected by disputes regarding intellectual property rights, and the value of our intellectual property rights is uncertain. We may become involved in dispute resolution or litigation proceedings from time to time to protect and enforce our intellectual property rights. In these dispute resolution or litigation proceedings, a third-party defendant may assert that our intellectual property rights are invalid or unenforceable. Third parties from time to time may also initiate dispute resolution or litigation proceedings against us by asserting that our businesses infringe, impair, misappropriate, dilute, or otherwise violate another party’s intellectual property rights. For example, in April 2020, a third party filed a lawsuit asserting that our BreakThru Casing Flotation DeviceTM infringed its intellectual property rights. In January 2022, a jury in the Western District of Texas, Waco Division, found in the third party’s favor. However, we intend to appeal the jury’s verdict. We may not prevail in such appeal or in any dispute resolution proceedings relating to intellectual property rights, and our intellectual property rights may be found invalid or unenforceable or our products and services may be found to infringe, impair, misappropriate, dilute, or otherwise violate the intellectual property rights of others. Also, as a part of resolving such disputes, we may enter into cross-licenses or other agreements, which could reduce the value of our existing intellectual property rights. The results or costs of any such dispute resolution or litigation proceedings may have an adverse effect on our business, operating results, and financial condition. Any dispute resolution or litigation proceeding concerning intellectual property could be protracted and costly, is inherently unpredictable, and could have an adverse effect on our business, regardless of its outcome. Our success may be affected by our ability to implement new technologies and services. Our success may be affected by the ongoing development and implementation of new product designs, methods, and improvements, and our ability to protect, obtain, and maintain intellectual property assets related to these developments. If we are not able to obtain patent or other protection of our technology, it may not be economical for us to continue to develop systems, services, and technologies to meet evolving industry requirements at prices acceptable to our customers. Further, we may face competitive pressure to develop, implement, or acquire certain new technologies at a substantial cost. Although we take measures to ensure that we use advanced 27 technologies, changes in technology or improvements in our competitors’ equipment could make our equipment less competitive or require significant capital investments to keep our equipment competitive. Our long-term success depends, in part, on our ability to effectively address changing customer demands, as well as government regulation and required disclosure regarding ESG. These demands and regulations include, but are not limited to, the creation of ESG-related policies and procedures, the quantification of our greenhouse gas emissions and evaluation of risk and opportunities. These customer preferences and government requirements could cause us to continue to adapt our equipment and technology offerings, as well as increase internal costs to address changes in ESG requirements. If ESG-related requirements change faster than anticipated or in a manner we do not anticipate, demand for our services could be adversely affected. Some of our competitors are large national and multinational companies that may be able to devote greater financial, technical, manufacturing, and marketing resources to research and development of new systems, services, and technologies and may have a larger number of manufacturers for their products or ability to manufacture their own products. As competitors and others use or develop new or comparable technologies in the future, we may lose market share or be placed at a competitive disadvantage if we are not able to develop and implement new technologies or products on a timely basis or at an acceptable cost. If we are unable to compete effectively given these risks, our business and results of operations could be affected. We rely on a limited number of manufacturers to produce the proprietary products used in the provision of our services, which exposes us to risks. We currently rely on a limited number of manufacturers for production of the proprietary products used in the provision of our products and services. Termination of the manufacturing relationship with any of these manufacturers could affect our ability to provide such products and services to our customers. Although we believe other alternate sources of supply for our proprietary products exist, we would need to establish relationships with new manufacturers, which could potentially involve significant expense, delay, and potential changes to certain product components. Any protracted curtailment or interruptions of the supply of any of our key products, whether or not as a result of termination of our manufacturing relationships or patent infringement claims, could have a material adverse effect on our financial condition, business, and results of operations. Our operations are subject to cyber security risks that could have a material adverse effect on our results of operations and financial condition. The efficient operation of our business is dependent on our information technology (“IT”) systems. Accordingly, we rely upon the capacity, reliability, and security of our IT hardware and software infrastructure and our ability to expand and update this infrastructure in response to our changing needs. Our IT systems are subject to possible breaches and other threats that could cause us harm. If our systems for protecting against cyber security risks prove not to be sufficient, we could be adversely affected by, among other things, loss or damage of intellectual property, proprietary information, customer or business data; interruption of business operations; or additional costs to prevent, respond to, or mitigate cyber security attacks. These risks could have a material adverse effect on our business, financial condition, and results of operations and could lead to litigation or regulatory action against us. RISKS RELATED TO CERTAIN SIGNIFICANT STOCKHOLDERS Significant ownership of our common stock by certain stockholders could adversely affect our other stockholders. SCF VII, L.P. and SCF-VII(A), L.P. (collectively, “SCF”) owned approximately 27% of our outstanding common stock as of December 31, 2022. In addition, certain of our directors are currently employed by SCF. Consequently, SCF is able to strongly influence all matters that require approval by our stockholders, including the election and removal of directors, changes to our organizational documents, and approval of acquisition offers and other significant corporate transactions. In addition, another one of our stockholders beneficially owned approximately 10% of our outstanding common stock as of December 31, 2022. This concentration of ownership by a small group of stockholders will limit other stockholders’ ability to influence corporate matters, and as a result, 28 actions may be taken that other stockholders may not view as beneficial. For example, this concentration of ownership could have the effect of delaying or preventing a change in control or otherwise discouraging a potential acquirer from attempting to obtain control of us, which in turn could cause the market price of our common stock to decline or prevent our stockholders from realizing a premium over the market price for their shares of our common stock. This concentration of stock ownership may also adversely affect the trading price of our common stock to the extent investors perceive a disadvantage in owning stock of a company with significant stockholders. A significant reduction by SCF of its ownership interests in us could adversely affect us. We believe that SCF’s substantial ownership interest in us provides them with an economic incentive to assist us to be successful. SCF is not subject to any obligation to maintain its ownership interest in us and may elect at any time to sell all or a substantial portion of or otherwise reduce its ownership interest in us. If SCF sells all or a substantial portion of its ownership interest in us, it may have less incentive to assist in our success and its affiliates that serve as members of our board of directors may resign. Such actions could adversely affect our ability to successfully implement our business strategies, which could adversely affect our cash flows or results of operations. Certain of our directors may have conflicts of interest because they are also affiliates of SCF. The resolution of these conflicts of interest may not be in our or other stockholders’ best interests. Certain of our directors, namely David C. Baldwin and Andrew L. Waite, are currently officers of SCF’s ultimate general partner. In addition, Mr. Waite is a director of National Energy Reunited Corp., a corporation in which SCF owns an approximate 9% equity interest as of December 31, 2022. These positions may conflict with such individuals’ duties as one of our directors regarding business dealings and other matters between SCF and us. The resolution of these conflicts may not always be in our or our other stockholders’ best interest. SCF and its affiliates are not limited in their ability to compete with us, and the corporate opportunity provisions in our charter could enable SCF to benefit from corporate opportunities that may otherwise be available to us. SCF and its affiliates have investments in other oilfield service companies that may compete with us, and SCF and its affiliates may invest in such other companies in the future. SCF, its other affiliates, and its other portfolio companies are referred to herein as the “SCF Group.” Conflicts of interest could arise in the future between us, on the one hand, and the SCF Group, on the other hand, concerning among other things, potential competitive business activities or business opportunities. Our charter provides that, to the fullest extent permitted by applicable law, we renounce any interest or expectancy in any business opportunity that involves any aspect of the energy equipment or services business or industry and that may be from time to time presented to SCF or any of our directors or officers who is also an employee, partner, member, manager, officer, or director of any SCF Group entity, even if the opportunity is one that we might reasonably have pursued or had the ability or desire to pursue if granted the opportunity to do so. Our charter further provides that no such person or party shall be liable to us by reason of the fact that such person pursues any such business opportunity or fails to offer any such business opportunity to us. As a result, any of our directors or officers who is also an employee, partner, member, manager, officer, or director of any SCF Group entity may become aware, from time to time, of certain business opportunities, such as acquisition opportunities, and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Further, such businesses may choose to compete with us for these opportunities. As a result, by renouncing our interest and expectancy in any business opportunity that may be from time to time presented to any member of an SCF Group entity or any of our directors or officers who is also an employee, partner, member, manager, officer, or director of any SCF Group entity, our business or prospects could be adversely affected if attractive business opportunities are procured by such parties for their own benefit rather than for ours. Our charter provides that any amendment to or adoption of any provision inconsistent with our charter’s provisions governing the renouncement of business opportunities must be approved by the holders of at least 80% of the voting power of the outstanding stock of the corporation entitled to vote thereon. Any actual or perceived conflicts of interest with respect to the foregoing could have an adverse impact on the trading price of our common stock. 29 RISKS RELATED TO HUMAN CAPITAL Our executive officers and certain key personnel are critical to our business, and these officers and key personnel may not remain with us in the future. Our future success depends in substantial part on our ability to hire and retain our executive officers and other key personnel. In particular, we are highly dependent on certain of our executive officers, particularly our President and Chief Executive Officer, Ann G. Fox, and the Chief Operating Officer, David Crombie. These individuals possess extensive expertise, talent, and leadership, and they are critical to our success. The diminution or loss of the services of these individuals, or other integral key personnel affiliated with entities that we acquire in the future, could have a material adverse effect on our business. Furthermore, we may not be able to enforce all of the provisions in any employment agreement we have entered into with certain of our executive officers, and such employment agreements may not otherwise be effective in retaining such individuals. In addition, we may not be able to retain key employees of entities that we acquire in the future, which may impact our ability to successfully integrate or operate the assets we acquire. We may be unable to employ, or maintain the employment of, a sufficient number of key employees, technical personnel, and other skilled and qualified workers. The delivery of our services and products requires personnel with specialized skills and experience, including personnel who can perform physically demanding work, and our success depends, in large part, upon our ability to employ and retain key employees, technical personnel, and other skilled and qualified workers. To attract and retain qualified employees, we must compensate them at market levels. If we are unable to continue to attract and retain qualified employees, or do so at rates necessary to maintain our liquidity and competitive position, our business, financial condition or results of operations could suffer. Workers may choose to pursue employment with our competitors or in fields that offer a more desirable work environment as a result of the volatility in the oilfield service industry and the demanding nature of our work. There has been a reduction of the available skilled labor force to service the energy industry. To the extent that there is an increase in demand for our products or services, there is no assurance that the availability of skilled labor will improve. If we are unable to employ and retain skilled workers, our capacity and profitability could be diminished, and our growth potential could be impaired. OTHER MATERIAL RISKS The coronavirus pandemic and related economic repercussions have had, and may continue to have, a material adverse effect on our business, liquidity, results of operations, and financial condition. The coronavirus pandemic and related economic repercussions created, and any resurgence of the pandemic or emergence of another global or national health epidemic or concern could again create significant volatility, uncertainty, and turmoil in the oil and gas industry and significant weakening of the demand for our services and products. Other effects included, and or may in the future include: disruption to our supply chain for raw materials essential to our business, including restrictions on importing and exporting products; disruptions to our operations due to lockdowns or other governmental restrictions or due to employee impacts from illness; liquidity challenges, including impacts related to delayed customer payments and payment defaults associated with customer liquidity issues and bankruptcies; limitations on access to sources of liquidity or higher borrowing costs due to significant volatility or disruption of the global financial markets; a need to preserve liquidity, which could result in a delay or change in our capital investment plan; cyber security issues, as digital technologies may become more vulnerable and experience a higher rate of cyber attacks in an environment of remote connectivity; reduction of our workforce to adjust to market conditions, which could result in severance payments, retention issues, and an inability to hire employees when market conditions improve; impairments along with other accounting charges as demand for our services and products decreases; changes in the regulation of the production of hydrocarbons, such as the imposition of limitations on the production of oil and gas by states or other jurisdictions, that may result in additional limits on demand for our products and services; and a structural shift in the global economy and its demand for oil and natural gas as a result of changes in the way people work, travel, and interact, or in connection with a global recession or depression. The extent to which our operating and financial results will continue to be affected by the pandemic will depend on various factors beyond our control, such as the continued severity of the pandemic, 30 including any sustained geographic resurgence; the emergence of new variants and strains of the coronavirus; and the success of actions to contain or treat the coronavirus. The coronavirus or other pandemic, and volatile regional and global economic conditions stemming therefrom, could also aggravate our other risk factors described in this Annual Report. We do not intend to pay dividends on our common stock, and our debt agreements place certain restrictions on our ability to do so. Consequently, a stockholder’s only opportunity to achieve a return on his investment is if the price of our common stock appreciates. We do not plan to declare dividends on shares of our common stock in the foreseeable future. Additionally, our debt agreements place certain restrictions on our ability to pay cash dividends. Consequently, unless we revise our dividend policy, a stockholder’s only opportunity to achieve a return on his investment in us will be by selling his common stock at a price greater than the stockholder paid for it. There is no guarantee that the price of our common stock that will prevail in the market will ever exceed the price at which a stockholder purchased his shares of our common stock. We have operated at a loss in the past, and there is no assurance of our profitability in the future. We have in the past experienced periods of low demand for our products and services and have incurred operating losses. In the future, we may not be able to reduce our costs, increase our revenues, or reduce our debt service obligations sufficiently to achieve or maintain profitability and generate positive operating income. Under such circumstances, we may incur operating losses and experience negative operating cash flow. Our future financial condition and results of operations could be adversely impacted by long-lived assets or other asset impairment charges. Determining whether an impairment exists and the amount of the potential impairment involves quantitative data and qualitative criteria that are based on estimates and assumptions requiring significant management judgment, such as those relating to revenue growth rates, future cash flows, and future market conditions. Future events or new information, including regarding the general economic environment, E&P activity levels, our financial performance and trends, and our strategies and business plans, may change management’s valuation of long-lived assets, other intangible assets, or other assets in a short amount of time. In particular, prolonged periods of decreased demand, low utilization, changes in technology or market conditions, or sales and other dispositions of assets for amounts less than their carrying value may cause us to recognize impairment charges relating to our long- lived assets, other intangible assets, or other assets that reduce our net income. While we believe our estimates and assumptions used in impairment tests are reasonable, we cannot provide assurance that additional impairment charges in the future will not be required, especially if an economic downturn occurs and continues for a lengthy period or becomes severe or if our acquisitions and investments fail to achieve expected returns. Significant impairment charges as a result of a decline in market conditions or otherwise could have a material adverse effect on our financial condition or results of operations in future periods. A terrorist attack or armed conflict could harm our business. The occurrence or threat of terrorist attacks in the U.S. or other countries, anti-terrorist efforts, and other armed conflicts involving the U.S. or other countries, including continued hostilities in the Middle East, may adversely affect the U.S. and global economies and could prevent us from meeting financial and other obligations. We could experience loss of business, delays or defaults in payments from payors, or disruptions of fuel supplies and markets if wells, operations sites, or other related facilities are direct targets or indirect casualties of an act of terror or war. Such activities could reduce the overall demand for oil and natural gas, which, in turn, could also reduce the demand for our products and services. Oil and natural gas-related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all. Terrorist activities and the threat of potential terrorist activities and any resulting economic downturn could adversely affect our results of operations, impair our ability to raise capital, or otherwise adversely impact our ability to realize certain business strategies. 31 A portion of our revenue is derived from sales to customers outside of the U.S., which exposes us to risks inherent in doing business internationally. In 2022, we derived 4.2% of our revenue from sales to customers outside of the U.S. Sales to customers in countries other than the U.S. are subject to various risks, including: • volatility in political, social, and economic conditions; • social unrest, acts of terrorism, war, or other armed conflicts; • confiscatory taxation or other adverse tax policies; • deprivation of contract rights; • trade and economic sanctions or other restrictions imposed by the European Union, the U.S., or other countries; • exposure under the FCPA or similar legislation, as discussed in the below risk factor; and • currency exchange controls. Our charter and bylaws contain provisions that could delay, discourage, or prevent a takeover attempt even if a takeover might be beneficial to our stockholders, and such provisions may adversely affect the market price of our common stock. Provisions contained in our charter and bylaws could make it more difficult for a third party to acquire us. Our charter and bylaws also impose various procedural and other requirements, which could make it more difficult for stockholders to effect certain corporate actions. For example, our charter authorizes our board of directors to determine the rights, preferences, privileges, and restrictions of unissued series of preferred stock without any vote or action by our stockholders. Thus, our board of directors can authorize and issue shares of preferred stock with voting or conversion rights that could adversely affect the voting or other rights of holders of our capital stock. These rights may have the effect of delaying or deterring a change of control of our company. Additionally, for example, our bylaws (i) establish limitations on the removal of directors and on the ability of our stockholders to call special meetings, (ii) include advance notice requirements for nominations for election to our board of directors and for proposing matters that can be acted upon at stockholder meetings, (iii) provide that our board of directors is expressly authorized to adopt, or to alter or repeal, our bylaws, and (iv) provide for a classified board of directors, consisting of three classes of approximately equal size, each class serving staggered three-year terms, so that only approximately one-third of our directors will be elected each year. These provisions could limit the price that certain investors might be willing to pay in the future for shares of our common stock. Our charter and bylaws designate the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees, or agents. Our charter and bylaws provide that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery 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 or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees, or agents to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law (the “DGCL”), our charter or our bylaws, or (iv) any action asserting a claim against us that is 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. These exclusive forum provisions are not intended to apply to actions arising under the Exchange Act or the Securities Act of 1933, as amended. The Court of Chancery of the State of Delaware has recently held that a Delaware corporation can only use its constitutive documents to bind a plaintiff to a particular forum where the claim involves rights or relationships that were established by or under the DGCL. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the forum selection provisions of our charter and bylaws. These choice of forum provisions may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for 32 disputes with us or our directors, officers, employees, or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our charter or bylaws 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. Taking advantage of the reduced disclosure requirements applicable to “emerging growth companies” may make our common stock less attractive to investors. We are an “emerging growth company,” as defined in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”), and we will remain an emerging growth company until the earliest to occur of (i) the last day of the fiscal year in which we have more than $1.07 billion in annual revenue; (ii) the date on which we become a “large accelerated filer” (the fiscal year-end on which at least $700 million of equity securities are held by non-affiliates as of the last day of our then most recently completed second fiscal quarter); (iii) the date on which we have issued, in any three-year period, more than $1.0 billion in non-convertible debt securities; and (iv) December 31, 2023, which is the last day of the fiscal year ending after the fifth anniversary of the completion of our initial public offering (the “IPO”). An emerging growth company may take advantage of certain reduced reporting and other requirements that are otherwise applicable generally to public companies. Pursuant to these reduced disclosure requirements, emerging growth companies are not required to, among other things, comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act of 2002, provide certain disclosures regarding executive compensation, hold stockholder advisory votes on executive compensation, or obtain stockholder approval of any golden parachute payments not previously approved. In addition, emerging growth companies have longer phase-in periods for the adoption of new or revised financial accounting standards. Under the JOBS Act, emerging growth companies can delay adopting new or revised accounting standards until such time as those standards apply to private companies. We intend to take advantage of all of the reduced reporting requirements and exemptions, including the longer phase-in periods for the adoption of new or revised financial accounting standards under Section 107 of the JOBS Act, until we are no longer an emerging growth company. If we were to subsequently elect instead to comply with these public company effective dates, such election would be irrevocable pursuant to Section 107 of the JOBS Act. Our election to use the phase-in periods permitted by this election may make it difficult to compare our financial statements to those of non-emerging growth companies and other emerging growth companies that have opted out of the longer phase-in periods under Section 107 of the JOBS Act and who will comply with new or revised financial accounting standards. We cannot predict if investors will find our common stock less attractive because we will rely on these exemptions. If some investors find our common stock less attractive as a result, there may be a less active trading market for our common stock and our common stock price may be more volatile. On the other hand, once we are no longer an emerging growth company, compliance with rules and regulations that do not currently apply to us as an emerging growth company will increase our legal and financial compliance costs, may make some activities more difficult, time-consuming, or costly, and will increase demand on our systems and resources. We may not be able to utilize a portion of our net operating loss carry forwards (“NOLs”) to offset future taxable income for U.S. federal or state tax purposes, which could adversely affect our net income and cash flows. As of December 31, 2022, we had federal and state income tax NOLs of approximately $442.2 million, which will begin to expire between 2023 and 2034. Utilization of these NOLs depends on many factors, including our future taxable income, which cannot be assured. In addition, Section 382 of the Internal Revenue Code of 1986, as amended (“Section 382”), generally imposes an annual limitation on the amount of an NOL that may be used to offset taxable income when a corporation has undergone an “ownership change” (as determined under Section 382). Determining the limitations under Section 382 is technical and highly complex. An ownership change generally occurs if one or more shareholders (or groups of shareholders) who are each deemed to own at least 5% of the 33 corporation’s stock increase their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling three-year period. In the event that an ownership change has occurred, or were to occur, with respect to a corporation following its recognition of an NOL, utilization of such NOL would be subject to an annual limitation under Section 382, generally determined by multiplying the value of the corporation’s stock at the time of the ownership change by the applicable long-term tax-exempt rate (as defined in Section 382). However, this annual limitation would be increased under certain circumstances by recognized built-in gains of the corporation existing at the time of the ownership change. In the case of an NOL that arose in a taxable year beginning before January 1, 2018, any unused annual limitation with respect to an NOL generally may be carried over to later years, subject to the expiration of such NOL 20 years after it arose. The issuance of additional stock in the IPO, combined with ownership shifts over the rolling three-year period, resulted in an ownership change under Section 382, and we may be prevented from fully utilizing our NOLs prior to their expiration. Future changes in our stock ownership or future regulatory changes could also limit our ability to utilize our NOLs. To the extent we are not able to offset future taxable income with our NOLs, our net income and cash flows may be adversely affected. ITEM 1B. UNRESOLVED STAFF COMMENTS None. ITEM 2. PROPERTIES The following table describes the material facilities owned or leased by us as of December 31, 2022. Location Basin/Region Leased or Owned Houston, TX Athens, TX Baker, MT Bergen, Norway Charleroi, PA Corpus Christi, TX Corpus Christi, TX Corpus Christi, TX Dickinson, ND El Reno, OK Fort Worth, TX Hobbs, NM Jacksboro, TX Jacksboro, TX Kilgore, TX Lacombe, AB, Canada Longview, TX Marietta, OH Mead, CO Midland, TX Monahans, TX Oklahoma City, OK Pleasanton, TX Poolville, TX Sweetwater, TX Tyler, TX Ulster, PA Williston, ND — — Bakken — — — — Bakken — Permian Barnett Barnett Haynesville WCSB Haynesville Leased Leased Owned Leased Marcellus/Utica Leased Leased Leased Leased Leased SCOOP/STACK Leased Leased Leased Leased Leased Leased Leased Owned Marcellus/Utica Leased Leased Leased Leased SCOOP/STACK Leased Leased Owned Leased Leased Marcellus/Utica Leased Owned Eagle Ford — Permian Haynesville Rockies Permian Permian Bakken Principal/Most Significant Use Corporate Headquarters/Administrative Operations Operations/Administrative Operations Operations Operations/Administrative Operations/Administrative Administrative Operations/Administrative Operations Administrative Operations Operations Operations Operations Operations/Administrative Operations Operations/Administrative Operations Operations/Administrative Operations/Administrative Operations Operations Operations Operations Operations Operations Operations/Administrative 34 ITEM 3. LEGAL PROCEEDINGS From time to time, we have various claims, lawsuits, and administrative proceedings that are pending or threatened with respect to personal injury, workers’ compensation, contractual matters, and other matters. Although no assurance can be given with respect to the outcome of these claims, lawsuits, or proceedings or the effect such outcomes may have, we believe any ultimate liability resulting from the outcome of such claims, lawsuits, or administrative proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on our business, operating results, or financial condition. For additional information related to legal proceedings, see Note 12 – Commitments and Contingencies included in Item 8 of Part II of this Annual Report. ITEM 4. MINE SAFETY DISCLOSURES Not applicable. 35 PART II ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES MARKET INFORMATION Nine Energy Service, Inc.’s common stock is traded on the New York Stock Exchange under the symbol “NINE.” HOLDERS As of March 3, 2023, we had 57 stockholders of record. The number of record holders does not include persons who held shares of our common stock in nominee or “street name” accounts through brokers. DIVIDEND POLICY We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to fund our operations and to develop and grow our business. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors our board of directors deems relevant, including our results of operations, financial condition, capital requirements, and investment opportunities, as well as any restrictions on our ability to pay cash dividends. RECENT SALES OF UNREGISTERED SECURITIES None. PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS The following table sets forth our repurchases of our equity securities registered under Section 12 of the Exchange Act that have occurred during the three months ended December 31, 2022: Maximum Number (or Approximate Dollar Value) of Shares That May Yet be Purchased Under the Plans or Programs Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs — — — — — — — — Total Number of Shares Purchased (a) Average Price Paid per Share 244 — — 244 $2.64 — — $2.64 October 1, 2022 – October 31, 2022 November 1, 2022 – November 30, 2022 December 1, 2022 – December 31, 2022 Total (a) Reflects the number of shares we have withheld to pay taxes upon vesting of restricted stock. ITEM 6. [RESERVED] 36 ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Financial Statements and Supplementary Data” in Item 8 of Part II of this Annual Report. This discussion contains forward-looking statements based on our current expectations, estimates, and projections about our operations and the industry in which we operate. Our actual results may differ materially from those anticipated in these forward- looking statements as a result of a variety of risks and uncertainties, including those described under “Risk Factors” in Item 1A of Part I of this Annual Report. We assume no obligation to update any of these forward-looking statements. OVERVIEW Company Description We are a leading North American onshore completion services provider that targets unconventional oil and gas resource development. We partner with our E&P customers across all major onshore basins in both the U.S. and Canada as well as abroad to design and deploy downhole solutions and technology to prepare horizontal, multistage wells for production. We focus on providing our customers with cost-effective and comprehensive completion solutions designed to maximize their production levels and operating efficiencies. Generally, operators have continued to improve operational efficiencies in completions design, increasing the complexity and difficulty, making oilfield service selection more important. This increase in high-intensity, high- efficiency completions of oil and gas wells further enhances the demand for our services. We compete for the most complex and technically demanding wells in which we specialize, which are characterized by extended laterals, increased stage spacing, multi-well pads, cluster spacing, and high proppant loads. These well characteristics lead to increased operating leverage and returns for us, as we are able to complete more jobs and stages with the same number of units and crews. Service providers for these projects are selected based on their technical expertise and ability to execute safely and efficiently. We provide (i) cementing services, which consist of blending high-grade cement and water with various solid and liquid additives to create a cement slurry that is pumped between the casing and the wellbore of the well, (ii) an innovative portfolio of completion tools, including those that provide pinpoint frac sleeve system technologies as well as a portfolio of completion technologies used for completing the toe stage of a horizontal well and fully- composite, dissolvable, and extended range frac plugs to isolate stages during plug-and-perf operations, (iii) wireline services, the majority of which consist of plug-and-perf completions, which is a multistage well completion technique for cased-hole wells that consists of deploying perforating guns and isolation tools to a specified depth, and (iv) coiled tubing services, which perform wellbore intervention operations utilizing a continuous steel pipe that is transported to the wellsite wound on a large spool in lengths of up to 30,000 feet and which provides a cost- effective solution for well work due to the ability to deploy efficiently and safely into a live well. We believe our success is a product of our culture, which is driven by our intense focus on performance and wellsite execution as well as our commitment to forward-leaning technologies that aid us in the development of smarter, customized applications that drive efficiencies. Recent Events On January 30, 2023, we completed our public offering of 300,000 units with an aggregate stated amount of $300.0 million (the “Units”). Each Unit consists of $1,000 principal amount of the 2028 Notes and five shares of our common stock. We received proceeds of $279.8 million from the Units offering, after deducting underwriting discounts and commission, which was deposited with the trustee of the 8.750% Senior Notes due 2023 (the “2023 Notes”), along with $40.0 million of cash received from borrowings under the ABL Credit Facility. On January 30, 2023, we instructed the trustee of the 2023 Notes to apply such deposits toward the payment of the 2023 Notes on February 1, 2023, and we elected to discharge the indenture governing the 2023 Notes, thereby releasing us from our remaining obligations under such indenture as of January 30, 2023. 37 On February 1, 2023, all of the outstanding 2023 Notes were redeemed at a redemption price of 100.0% of the principal amount thereof ($307.3 million), plus accrued and unpaid interest ($6.7 million). We also wrote off the unamortized deferred financing costs associated with the 2023 Notes in conjunction with the redemption. For additional information on our Units offering, the ABL Credit Facility, which was amended in connection with such offering, and the redemption of the 2023 Notes, see Note 9 – Debt Obligations included in Item 8 of Part II of this Annual Report. How We Generate Revenue and the Costs of Conducting Our Business We generate our revenues by providing completion services to E&P customers across all major onshore basins in both the U.S. and Canada as well as abroad. We primarily earn our revenues pursuant to work orders entered into with our customers on a job-by-job basis. We typically will enter into an MSA with each customer that provides a framework of general terms and conditions of our services that will govern any future transactions or jobs awarded to us. Each specific job is obtained through competitive bidding or as a result of negotiations with customers. The rate we charge is determined by location, complexity of the job, operating conditions, duration of the contract, and market conditions. In addition to MSAs, we have entered into a select number of longer-term contracts with certain customers relating to our wireline and cementing services, and we may enter into similar contracts from time to time to the extent beneficial to the operation of our business. These longer-term contracts address pricing and other details concerning our services, but each job is performed on a standalone basis. The principal expenses involved in conducting our business include labor costs, materials and freight, the costs of maintaining our equipment, and fuel costs. Our direct labor costs vary with the amount of equipment deployed and the utilization of that equipment. Another key component of labor costs relates to the ongoing training of our field service employees, which improves safety rates and reduces employee attrition. How We Evaluate Our Operations We evaluate our performance based on a number of financial and non-financial measures, including the following: • Revenue: We compare actual revenue achieved each month to the most recent projection for that month and to the annual plan for the month established at the beginning of the year. We monitor our revenue to analyze trends in the performance of our operations compared to historical revenue drivers or market metrics. We are particularly interested in identifying positive or negative trends and investigating to understand the root causes. • Adjusted Gross Profit (Loss): Adjusted gross profit (loss) is a key metric that we use to evaluate operating performance. We define adjusted gross profit (loss) as revenues less direct and indirect costs of revenues (excluding depreciation and amortization). Costs of revenues include direct and indirect labor costs, costs of materials, maintenance of equipment, fuel and transportation freight costs, contract services, crew cost, and other miscellaneous expenses. For additional information, see “Non-GAAP Financial Measures” below. • Adjusted EBITDA: We define Adjusted EBITDA as net income (loss) before interest, taxes, and depreciation and amortization, further adjusted for (i) goodwill, intangible asset, and/or property and equipment impairment charges, (ii) transaction and integration costs related to acquisitions, (iii) loss or gain on revaluation of contingent liabilities, (iv) loss or gain on the extinguishment of debt, (v) loss or gain on the sale of subsidiaries, (vi) restructuring charges, (vii) stock-based compensation and cash award expense, (viii) loss or gain on sale of property and equipment, and (ix) other expenses or charges to exclude certain items which we believe are not reflective of ongoing performance of our business, such as legal expenses and settlement costs related to litigation outside the ordinary course of business. For additional information, see “Non-GAAP Financial Measures” below. • Return on Invested Capital (“ROIC”): We define ROIC as after-tax net operating profit (loss), divided by average total capital. We define after-tax net operating profit (loss) as net income (loss) plus (i) goodwill, intangible asset, and/or property and equipment impairment charges, (ii) transaction and integration costs related to acquisitions, (iii) interest expense (income), (iv) restructuring charges, (v) loss (gain) on the sale of subsidiaries, (vi) loss (gain) on the extinguishment of debt, and (vii) the provision (benefit) for deferred 38 income taxes. We define total capital as book value of equity plus the book value of debt less balance sheet cash and cash equivalents. We compute the average of the current and prior period-end total capital for use in this analysis. For additional information, see “Non-GAAP Financial Measures” below. • Safety: We measure safety by tracking the total recordable incident rate (“TRIR”), which is reviewed on a monthly basis. TRIR is a measure of the rate of recordable workplace injuries, defined below, normalized and stated on the basis of 100 workers for an annual period. The factor is derived by multiplying the number of recordable injuries in a calendar year by 200,000 (i.e., the total hours for 100 employees working 2,000 hours per year) and dividing this value by the total hours actually worked in the year. A recordable injury includes occupational death, nonfatal occupational illness, and other occupational injuries that involve loss of consciousness, restriction of work or motion, transfer to another job, or medical treatment other than first aid. Industry Trends and Outlook Our business depends, to a significant extent, on the level of unconventional resource development activity and corresponding capital spending of oil and natural gas companies. These activity and spending levels are strongly influenced by current and expected oil and natural gas prices. Throughout 2022, oil and natural gas prices were very supportive, with an average WTI price of $94.90 for the year, although prices began to decline during the third quarter of 2022 in response to some indications of slowing economic growth, inflation, and rising interest rates. In addition, over the last several months, we have seen a sharp decline in natural gas prices, which has and will likely continue to affect activity levels in the Northeast and Haynesville. We anticipate these effects will be felt more strongly in the Haynesville in the near-term. Industry dynamics can shift very quickly, however, and we are operating this business for the long-term. Together, the Northeast and Haynesville comprised 30% of our total 2022 revenue, and we believe that these basins are vital to supplying the global markets and are important pieces of our footprint. In 2022, operators increased activity levels with the average U.S. rig count, according to Baker Hughes, increasing by 51% year over year. Total U.S. completions in 2022 increased by approximately 22% over 2021 according to the Energy Information Administration (the “EIA”). Activity levels, specifically rig counts, thus far in the first quarter of 2023 have been down compared to the fourth quarter of 2022, with the rig count declining by 26 rigs since the end of 2022. Nonetheless, we expect U.S. E&P capital expenditure levels to increase in 2023, although not likely at the same rate as 2022. Underinvestment in oil and gas development during the coronavirus pandemic and an increase in overall global demand coming out of the pandemic, production cuts announced by OPEC, international conflict, specifically between Russia and Ukraine, and public U.S. producers’ commitment to capital discipline rather than increased drilling, are together creating supportive market fundamentals for a longer cycle. The U.S. average drilled but uncompleted wells inventory in 2022 was down by over 40% from the average 2019 levels, and operators will need to drill more wells to maintain production levels in 2023. In a recent report, the EIA is forecasting U.S. production will increase from 11.90 mb/d in 2022 to 12.49 mb/d in 2023. Throughout 2022, the oilfield services industry faced labor shortages, as well as equipment and supply chain constraints, which limited availability for customers. As a result, in 2022, we implemented price increases across many of our service lines. Potential price increases in 2023 will be dependent on activity increases, as well as a number of other factors, and pricing has remained mostly steady thus far in 2023 across service lines. Any price increases in 2023 could be largely or wholly offset by labor and material cost inflation, and any such price increases could also negatively impact our customers’ activity levels due to their own cost inflation. Significant factors that are likely to affect commodity prices moving forward include actions of the members of OPEC and other oil exporting nations that relate to or impact oil production or supply; the effect of energy, monetary, and trade policies of the U.S.; the pace of economic growth in the U.S. and throughout the world, including the potential for macro weakness; geopolitical and economic developments in the U.S. and globally, including conflicts, instability, acts of war or terrorism in oil producing countries or regions, particularly Russia, the Middle East, South America and Africa and including recovery from the coronavirus pandemic and any resurgence thereof; changes to energy regulations and policies, including those of the EPA and other governmental bodies; and overall North American oil and natural gas supply and demand fundamentals, including the pace at which export 39 capacity grows. Furthermore, although as noted above, our customers’ activity and spending levels, and thus demand for our services and products, are strongly influenced by current and expected oil and natural gas prices, even with price improvements in oil and natural gas, operator activity may not materially increase, as operators remain focused on operating within their capital plans, and uncertainty remains around supply and demand fundamentals. RESULTS OF OPERATIONS Revenues Revenues Cost of revenues (exclusive of depreciation and amortization shown separately below) Adjusted gross profit General and administrative expenses Depreciation Amortization of intangibles Loss on revaluation of contingent liability Loss on sale of property and equipment Income (loss) from operations Non-operating expenses Income (loss) before income taxes Provision (benefit) for income taxes Net income (loss) Year Ended December 31, 2022 2021 Change $593,382 457,093 $136,289 $ 51,653 26,784 13,463 454 367 43,568 28,629 14,939 546 $ 14,393 (in thousands) $349,419 307,992 $ 41,427 $ 45,301 28,905 16,116 460 660 (50,015) 14,585 (64,600) (25) $243,963 149,101 $ 94,862 6,352 $ (2,121) (2,653) (6) (293) 93,583 14,044 79,539 571 $ (64,575) $ 78,968 Revenues Revenues increased $244.0 million, or 70%, to $593.4 million in 2022. The increase in comparison to 2021 was prevalent across all lines of service and was due to activity and pricing improvements. As compared to 2021, the average U.S. rig count increased by 51%, and completions increased by 22%. Cementing revenue (including pump downs) increased by $115.3 million, or 101%, as total cement job count increased by 50%, in comparison to 2021. In addition, coiled tubing revenue increased $56.6 million, or 91%, as total days worked increased by 37%, tools revenue increased $37.2 million, or 37%, as completion tools stages increased by 38%, and wireline revenue increased $34.9 million, or 48%, as total completed wireline stages increased by 26%, in each case, in comparison to 2021. Cost of Revenues (Exclusive of Depreciation and Amortization) Cost of revenues increased $149.1 million, or 48%, to $457.1 million in 2022. The increase in comparison to 2021 was prevalent across all lines of service and was primarily related to increased activity coupled with cost inflation associated with both labor and materials as well as headcount increases. More specifically, the increase was related to a $79.2 million increase in materials installed and consumed while performing services, a $54.4 million increase in employee costs, and a $15.5 million increase in other costs such as repairs and maintenance, travel, and vehicle expenses, in comparison to 2021. Adjusted Gross Profit (Loss) Adjusted gross profit increased $94.9 million to $136.3 million in 2022 as a result of the factors described above under “Revenues” and “Cost of Revenues.” General and Administrative Expenses General and administrative expenses increased $6.4 million to $51.7 million in 2022. The increase in comparison to 2021 was primarily related to an $8.2 million increase in employee costs mainly due to increases in headcount and compensation and a $0.4 million increase in other general and administrative costs such as marketing, travel, and vehicle costs. The overall increase was partially offset by a $2.2 million decrease in professional fees in comparison to 2021. 40 Depreciation Depreciation expense decreased $2.1 million to $26.8 million in 2022. The decrease in comparison to 2021 was primarily due to certain assets becoming fully depreciated in the last twelve months. Amortization of Intangibles Intangible amortization expense decreased $2.7 million to $13.5 million in 2022 and was primarily attributable to technology and customer relationships. The decrease was related to certain intangible assets being fully amortized in 2022. (Gain) Loss on Revaluation of Contingent Liability We recorded a $0.5 million loss on the revaluation of contingent liability in both 2022 and 2021. The losses for both periods were related to increases of the value of the earnout associated with our acquisition Frac Technology AS. Non-Operating Expenses (Income) We recorded $28.6 million in non-operating expenses in 2022 compared to $14.6 million in non-operating expenses in 2021. The $14.0 million increase in non-operating expense was primarily related to a $14.8 million decrease in gains on the extinguishment of debt related to the repurchase of 2023 Notes between periods. The overall increase in non-operating expenses was partially offset by a $0.7 million increase in interest and other income between periods. Provision (Benefit) for Income Taxes Our effective tax rate was 3.7% for 2022 and 0.01% for 2021. Our tax provision for 2022 is primarily the result of our tax position in state and foreign tax jurisdictions. Adjusted EBITDA Adjusted EBITDA increased $88.5 million to $93.7 million for 2022. The Adjusted EBITDA increase was primarily due to the changes in revenue and expenses discussed above. See “Non-GAAP Financial Measures” below for further explanation. NON-GAAP FINANCIAL MEASURES Adjusted EBITDA Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders, and rating agencies. We define Adjusted EBITDA as EBITDA (which is net income (loss) before interest, taxes, depreciation, and amortization) further adjusted for (i) goodwill, intangible asset, and/or property and equipment impairment charges, (ii) transaction and integration costs related to acquisitions, (iii) loss or gain on revaluation of contingent liabilities, (iv) loss or gain on the extinguishment of debt, (v) loss or gain on the sale of subsidiaries, (vi) restructuring charges, (vii) stock-based compensation and cash award expense, (viii) loss or gain on sale of property and equipment, and (ix) other expenses or charges to exclude certain items which we believe are not reflective of ongoing performance of our business, such as legal expenses and settlement costs related to litigation outside the ordinary course of business. Management believes Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in arriving at this measure because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures, and the method by which the assets were acquired. This measure should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with accounting principles generally accepted in the United States of America (“GAAP”) 41 or as an indicator of our operating performance. Certain items excluded from this measure are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of this measure. Our computation of this measure may not be comparable to other similarly titled measures of other companies. The following table presents a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measure of net income (loss): EBITDA reconciliation: Net income (loss) Interest expense Interest income Provision (benefit) for income taxes Depreciation Amortization of intangibles EBITDA Adjusted EBITDA reconciliation: EBITDA Loss on revaluation of contingent liability (1) Gain on extinguishment of debt Restructuring charges Stock-based compensation and cash award expense Loss on sale of property and equipment Legal fees and settlements (2) Adjusted EBITDA Year Ended December 31, 2022 2021 (in thousands) $14,393 32,486 (305) 546 26,784 13,463 $87,367 $87,367 454 (2,843) 3,393 4,914 367 86 $93,738 $(64,575) 32,527 (26) (25) 28,905 16,116 $ 12,922 $ 12,922 460 (17,618) 1,588 5,406 660 1,809 $ 5,227 (1) (2) Amounts relate to the revaluation of contingent liability associated with a 2018 acquisition. The impact is included in our Consolidated Statements of Income and Comprehensive Income (Loss). For additional information on contingent liabilities, see Note 12 – Commitments and Contingencies included Item 8 of Part II of this Annual Report. Amounts represent fees and legal settlements associated with legal proceedings brought pursuant to the FLSA and/or similar state laws. Return on Invested Capital ROIC is a supplemental non-GAAP financial measure. We define ROIC as after-tax net operating profit (loss), divided by average total capital. We define after-tax net operating profit (loss) as net income (loss) plus (i) goodwill, intangible asset, and/or property and equipment impairment charges, (ii) transaction and integration costs related to acquisitions, (iii) interest expense (income), (iv) restructuring charges, (v) loss (gain) on the sale of subsidiaries, (vi) loss (gain) on the extinguishment of debt, and (vii) the provision (benefit) for deferred income taxes. We define total capital as book value of equity (deficit) plus the book value of debt less balance sheet cash and cash equivalents. We compute the average of the current and prior period-end total capital for use in this analysis. Management believes ROIC is a meaningful measure because it quantifies how well we generate operating income relative to the capital we have invested in our business and illustrates the profitability of a business or project taking into account the capital invested. Management uses ROIC to assist them in capital resource allocation decisions and in evaluating business performance. Although ROIC is commonly used as a measure of capital efficiency, definitions of ROIC differ, and our computation of ROIC may not be comparable to other similarly titled measures of other companies. 42 The following table provides an explanation of our calculation of ROIC for the years ended December 31, 2022 and 2021: Net income (loss) Add back: Interest expense Interest income Restructuring charges Gain on extinguishment of debt After-tax net operating income (loss) Total capital as of prior period-end: Total stockholders’ equity (deficit) Total debt Less cash and cash equivalents Total capital as of prior period-end Total capital as of period-end: Total stockholders’ deficit Total debt Less cash and cash equivalents Total capital as of period-end Average total capital ROIC Adjusted Gross Profit (Loss) Year Ended December 31, 2022 2021 (in thousands) $ 14,393 $ (64,575) 32,486 (305) 3,393 (2,843) $ 47,124 $(39,267) 337,436 (21,509) $276,660 $(23,507) 341,606 (17,445) $300,654 $288,657 16.3% 32,527 (26) 1,588 (17,618) $ (48,104) $ 20,409 348,637 (68,864) $ 300,182 $ (39,267) 337,436 (21,509) $ 276,660 $ 288,421 (16.7)% GAAP defines gross profit (loss) as revenues less cost of revenues and includes depreciation and amortization in costs of revenues. We define adjusted gross profit (loss) as revenues less direct and indirect costs of revenues (excluding depreciation and amortization). This measure differs from the GAAP definition of gross profit (loss) because we do not include the impact of depreciation and amortization, which represent non-cash expenses. Management uses adjusted gross profit (loss) to evaluate operating performance. We prepare adjusted gross profit (loss) to eliminate the impact of depreciation and amortization because we do not consider depreciation and amortization indicative of our core operating performance. Adjusted gross profit (loss) should not be considered as an alternative to gross profit (loss), operating income (loss), or any other measure of financial performance calculated and presented in accordance with GAAP. Adjusted gross profit (loss) may not be comparable to similarly titled measures of other companies because other companies may not calculate adjusted gross profit (loss) or similarly titled measures in the same manner as we do. 43 The following table presents a reconciliation of adjusted gross profit (loss) to GAAP gross profit (loss). Calculation of gross profit (loss) Revenues Cost of revenues (exclusive of depreciation and amortization shown separately below) Depreciation (related to cost of revenues) Amortization of intangibles Gross profit (loss) Adjusted gross profit reconciliation: Gross profit (loss) Depreciation (related to cost of revenues) Amortization of intangibles Adjusted gross profit Year Ended December 31, 2022 2021 (in thousands) $593,382 457,093 24,909 13,463 $ 97,917 $349,419 307,992 26,882 16,116 $ (1,571) $ 97,917 24,909 13,463 $136,289 $ (1,571) 26,882 16,116 $ 41,427 LIQUIDITY AND CAPITAL RESOURCES Sources and Uses of Liquidity Historically, we have met our liquidity needs principally from cash on hand, cash flows from operations and, if needed, external borrowings and issuances of debt securities. Our principal uses of cash are to fund capital expenditures, service our outstanding debt, fund our working capital requirements and fund acquisitions. Due to our high level of variable costs and the asset-light make-up of our business, we have historically been able to quickly implement cost-cutting measures and will continue to adapt as the market dictates. We have also used cash to make open market repurchases of our debt and may, from time to time, continue to make such repurchases (including with respect to the 2028 Notes) when it is opportunistic to do so to manage our debt maturity profile. We continually monitor potential capital sources, including equity and debt financing, to meet our investment and target liquidity requirements. Our future success and growth will be highly dependent on our ability to continue to access outside sources of capital. Although we do not budget for acquisitions, pursuing growth through acquisitions may continue to be a part of our business strategy. Our ability to make significant additional acquisitions for cash will require us to obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us or at all. In 2023, our planned capital expenditure budget, excluding possible acquisitions, is expected to be between $25.0 million to $35.0 million. The nature of our capital expenditures is comprised of a base level of investment required to support our current operations and amounts related to growth and company initiatives. Capital expenditures for growth and company initiatives are discretionary. We continually evaluate our capital expenditures, and the amount we ultimately spend will depend on a number of factors, including expected industry activity levels and company initiatives. At December 31, 2022, we had $17.4 million of cash and cash equivalents and $66.6 million of availability under the ABL Credit Facility, which resulted in a total liquidity position of $84.0 million. On January 27, 2023, we borrowed an additional $40.0 million under the ABL Credit Facility to pay for the redemption price of the 2023 Notes and to pay for fees and expenses related to the Units offering. We believe that, based on our current forecasts, our cash on hand, together with cash flow from operations and borrowings under the ABL Credit Facility, should be sufficient to fund our capital requirements for at least the next twelve months from the issuance date of our consolidated financial statements. However, we can make no assurance regarding our ability to achieve our forecasts, which are materially dependent on our financial performance and the ever-changing market. 2023 Notes On October 25, 2018, we issued $400.0 million of 2023 Notes under an indenture, dated as of October 25, 2018 (the “2023 Notes Indenture”), by and among us, including certain of our subsidiaries, and Wells Fargo, 44 National Association, as Trustee. The 2023 Notes bore interest at annual rate of 8.750% payable on May 1 and November 1 of each year. The 2023 Notes were senior unsecured obligations and were fully and unconditionally guaranteed on a senior unsecured basis by each of our current domestic subsidiaries and by certain future subsidiaries. The 2023 Notes Indenture contained covenants that limited our ability and the ability of our restricted subsidiaries to engage in certain activities. We were in compliance with the provisions of the 2023 Notes Indenture at December 31, 2022. We repurchased approximately $13.0 million of 2023 Notes at a repurchase price of approximately $10.1 million in cash for the year ended December 31, 2022. We also repurchased approximately $26.3 million of 2023 Notes at a repurchase price of approximately $8.4 million in cash for the year ended December 31, 2021. On February 1, 2023, all of the outstanding 2023 Notes were redeemed at a redemption price of 100.0% of the principal amount thereof ($307.3 million), plus accrued and unpaid interest ($6.7 million), and the 2023 Notes Indenture was discharged as of January 30, 2023. For additional information on the 2023 Notes, see Note 9 – Debt Obligations included in Item 8 of Part II of this Annual Report. Units Offering and 2028 Notes On January 30, 2023, we completed our public offering of Units and issued 300,000 Units with an aggregate stated amount of $300.0 million. Each Unit consists of $1,000 principal amount of the 2028 Notes and five shares of our common stock. We received proceeds of $279.8 million from the Units offering, after deducting underwriting discounts and commission, which was used to fund a portion of the redemption price of the 2023 Notes. Each Unit will be separated into its constituent securities (the 2028 Notes and the shares of our common stock) automatically on October 27, 2023, or, if earlier, on the date, if any, on which a change of control or event of default (each as defined in the indenture governing the 2028 Notes) occurs. A holder of Units may elect to separate its Units into its constituent securities, in whole but not in part, on or after March 31, 2023. Prior to such date, the Units may not be separated at the option of the holder. On January 30, 2023, we, and certain of our subsidiaries entered into an indenture, dated as of January 30, 2023 (the “2028 Notes Indenture”), with U.S. Bank Trust Company, National Association, as the trustee and as notes collateral agent, pursuant to which the 2028 Notes, which form a part of the Units, were issued. The 2028 Notes will mature on February 1, 2028 and bear interest at an annual rate of 13.000% payable in cash semi- annually in arrears on each of February 1 and August 1, commencing August 1, 2023. The 2028 Notes are our senior secured obligations and are guaranteed on a senior secured basis by each of our current domestic subsidiaries and by certain future subsidiaries, subject to agreed guaranty and security principles and certain exclusions. On each May 15 and November 14, commencing November 14, 2023 (each, an “Excess Cash Flow Offer Date”), we are required to make an offer (an “Excess Cash Flow Offer”) to all holders of the 2028 Notes and, if required by the terms of any Pari Passu Notes Lien Indebtedness (as defined in the 2028 Notes Indenture), to any holders of any Pari Passu Notes Lien Indebtedness to purchase, prepay or redeem, together on a pro-rata basis, the maximum principal amount of the 2028 Notes and any such Pari Passu Notes Lien Indebtedness (plus all accrued interest (including additional interest, if any) on the 2028 Notes and any such Pari Passu Notes Lien Indebtedness and the amount of all fees and expenses, including premiums, incurred in connection therewith) that may be purchased, prepaid or redeemed using an amount of cash equal to the Excess Cash Flow Amount (as defined in the 2028 Notes Indenture and which is 75.0% of Excess Cash Flow (as defined in the 2028 Notes Indenture), as determined immediately prior to the Excess Cash Flow Offer Date), if any, subject to certain exceptions set forth in the 2028 Notes Indenture. The offer price in any such offer will be equal to 100% of the principal amount of the 2028 Notes and any such Pari Passu Notes Lien Indebtedness (or, in respect of any such Pari Passu Notes Lien 45 Indebtedness, such lesser price, if any, as may be provided for by the terms of such Pari Passu Notes Lien Indebtedness), plus accrued and unpaid interest and additional interest, if any, to, but excluding, the date of purchase, prepayment or redemption, subject to the rights of holders of the 2028 Notes or any such Pari Passu Notes Lien Indebtedness on the relevant record date to receive interest due on an interest payment date that is on or prior to the date of purchase, prepayment or redemption, and will be payable in cash. The 2028 Notes Indenture contains covenants that, among other things and subject to certain exceptions and qualifications, limit our ability and the ability of our restricted subsidiaries to engage in certain activities. For additional information on the Units and the 2028 Notes, see Note 9 – Debt Obligations included in Item 8 of Part II of this Annual Report. ABL Credit Facility On October 25, 2018, we entered into a credit agreement dated as of October 25, 2018 (the “2018 ABL Credit Agreement”), that permitted aggregate borrowings of up to $200.0 million, subject to a borrowing base, including a Canadian tranche with a sub-limit of up to $25.0 million and a sub-limit of $50.0 million for letters of credit (the “ABL Credit Facility”). Pursuant to the 2018 ABL Credit Agreement, the ABL Credit Facility was set to mature on October 25, 2023 or, if earlier, on the date that is 180 days before the scheduled maturity date of the 2023 Notes if they had not been redeemed or repurchased by such date. On January 17, 2023, we entered into the First Amendment to Credit Agreement (the “ABL Facility Amendment”) with JP Morgan Chase Bank, N.A., as administrative agent, and the lender parties thereto, which amends certain terms of the 2018 ABL Credit Agreement (as amended the “ABL Credit Agreement”). The ABL Facility Amendment became effective on January 30, 2023. Pursuant to the ABL Facility Amendment, the maturity date of the ABL Credit Facility was extended from October 25, 2023 to January 29, 2027. In addition, the ABL Facility Amendment, among other changes, revised the terms of the ABL Credit Facility as follows: (a) decreased the size of the ABL Credit Facility from $200.0 million to $150.0 million, subject to the borrowing base, (b) changed the interest rate benchmark from London Interbank Offered Rate to Term Secured Overnight Financing Rate with a 10 basis point spread adjustment and increased pricing from the existing range of 1.75% to 2.25% to a range of 2.00% to 2.50%, in each case depending on our leverage ratio, (c) modified the financial covenant, enhanced reporting and cash dominion triggers in the ABL Credit Facility from the existing minimum availability threshold of the greater of $18.75 million and 12.5% of the loan limit to a minimum availability threshold of (i) $12.5 million from January 30, 2023 until May 31, 2023 and (ii) the greater of $17.5 million and 12.5% of the loan limit thereafter, (d) decreased the Canadian tranche sub-limit from $25.0 million to $5.0 million, (e) decreased the letter of credit sub-limit from $50.0 million to $10.0 million and (f) made satisfaction of the Payment Conditions (as defined in the ABL Facility Amendment) a condition to an Excess Cash Flow Offer in addition to a condition to voluntary payments of the 2028 Notes. The Payment Conditions in summary are (A) no default or event of default on a pro forma basis and (B) immediately after and at all times and at all times during the 30 days prior, on a pro forma basis, (1) (x) availability under the ABL Credit Facility shall not be less than the greater of 15% of the loan limit and $22.5 million and (y) the fixed charge coverage ratio shall be at least 1.00 to 1.00 or (2) availability under the ABL Credit Facility shall not be less than the greater of 20% of the loan limit and $30.0 million. The 2018 ABL Credit Agreement contained, and the ABL Credit Agreement contains, various affirmative and negative covenants, including financial reporting requirements and limitations on indebtedness, liens, mergers, consolidations, liquidations and dissolutions, sales of assets, dividends and other restricted payments, investments (including acquisitions) and transactions with affiliates. We were in compliance with all covenants under the 2018 ABL Credit Agreement as of December 31, 2022. Pursuant to the 2018 ABL Credit Agreement, all of the obligations under the ABL Credit Facility were, and pursuant to the ABL Credit Agreement, all obligations under the ABL Credit Facility are, secured by security interests (subject to permitted liens) in substantially all of the personal property of our domestic subsidiaries, excluding certain assets. The obligations under the Canadian tranche were and are further secured by security 46 interests (subject to permitted liens) in substantially all of the personal property of Nine Energy Canada, Inc., a corporation organized under the laws of Alberta, Canada, and its restricted subsidiaries, excluding certain assets. Both the ABL Credit Facility and the Units collateralization were completed within 30 days after closing in accordance with the terms of the ABL Facility Amendment and the Units offering. At December 31, 2022, we had $32.0 million of borrowings under the ABL Credit Facility, and our availability under the ABL Credit Facility was approximately $66.6 million, net of outstanding letters of credit of $1.3 million. On January 27, 2023, we borrowed an additional $40.0 million under the ABL Credit Facility to pay for the redemption price of the 2023 Notes and to pay for fees and expenses related to the Units offering. Cash Flows Our cash flows for the years ended December 31, 2022, and 2021 are presented below: Operating activities Investing activities Financing activities Impact of foreign exchange rate on cash Net change in cash and cash equivalents Operating Activities Year Ended December 31, 2022 2021 (in thousands) $ 16,672 (25,417) 4,849 (168) $(40,416) (11,921) 5,048 (66) $ (4,064) $(47,355) Net cash provided by operating activities was $16.7 million in 2022 compared to $40.4 million in net cash used in operating activities in 2021. The $57.1 million increase in net cash provided by operating activities was primarily a result of an $85.5 million increase in cash flow provided by operations, adjusted for any non-cash items, and primarily driven by an increase in revenue and income in comparison to 2021. The increase in net cash provided by operating activities was offset by a $28.4 million decrease in cash provided by working capital, including an increase in accounts receivable from increased product and service sales, which has the effect of lagging cash collections, in each case, in comparison to 2021. Investing Activities Net cash used in investing activities was $25.4 million in 2022 compared to $11.9 million in net cash used in investing activities in 2021. The $13.5 million increase was primarily due to a $13.1 million increase in cash purchases of property and equipment, coupled with $0.4 million decrease in proceeds from the sale of property and equipment (including insurance), in each case, in comparison to 2021. Financing Activities Net cash provided by financing activities was $4.8 million in 2022 compared to $5.0 million in net cash provided by financing activities in 2021. The $0.2 million decrease was primarily related to a $7.0 million payment on the ABL Credit Facility in 2022 that did not occur in 2021 as well as a $2.2 million increase in payments on short-term debt in comparison to 2021. The decrease was partially offset by a $9.0 million increase in proceeds from the ABL Credit Facility in 2022 in comparison to 2021. Critical Accounting Estimates The discussion and analysis of our financial condition and results of operations are based upon our financial statements, which have been prepared in accordance with GAAP. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements. 47 We consider the significant accounting policies identified below to be “critical accounting estimates” due to the following: • The policies are dependent on estimates and assumptions made by us about matters that are inherently uncertain. • The policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. For additional information on our significant accounting policies, see Note 2 – Significant Accounting Policies included in Item 8 of Part II of this Annual Report. Property and Equipment Property and equipment is stated at cost and depreciated under the straight-line method over the estimated useful life of the asset. Equipment held under finance leases is stated at the present value of its future minimum lease payments and is depreciated under the straight-line method over the shorter of the lease term or the estimated useful life of the asset. Estimated useful lives requires significant judgment which is influenced by our historical experience in operating property and equipment, technological developments, and expectations of future demand. Should our estimates be too long or too short, we could report a disproportionate amount of losses or gains from sale or retirement. Valuation of Long-Lived Assets Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. In performing the review for impairment, future cash flows expected to result from the use of the asset and its eventual disposal are estimated. If the undiscounted future cash flows are less than the carrying amount of the assets, there is an indication that the asset may be impaired. The amount of the impairment is measured as the difference between the carrying value and the Level 3 fair value of the asset. The Level 3 fair value is determined either through the use of an external valuation, or by means of an analysis of discounted future cash flows based on expected utilization. Determining fair value requires the use of estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating profit margins, weighted average costs of capital, terminal growth rates, future market share, the impact of new product development, and future market conditions, among others. We believe that the estimates and assumptions used in impairment assessments are reasonable and appropriate. Impairment losses are reflected in “Income (loss) from operations” in our Consolidated Statements of Income and Comprehensive Income (Loss). Recognition of Provisions for Contingencies In the ordinary course of business, we are subject to various claims, suits, and complaints. We, in consultation with internal and external advisors, will provide for a contingent loss in the financial statements if it is probable that a liability has been incurred at the date of the financial statements and the amount can be reasonably estimated. Reasonable estimates are based upon an analysis of potential results, assuming a combination of litigation and settlement strategies. The accuracy of these estimates is impacted by, among other things, the complexity of the issues and the amount of due diligence we have been able to perform. If it is determined that the reasonable estimate of the loss is a range and that there is no best estimate within the range, provision will be made for the lower amount of the range. If the actual settlement costs, final judgments, or fines, after appeals, differ from our estimates, there may be a material adverse effect on our future financial results. Stock-based Compensation and Fair Market Value Determination We account for awards of stock-based compensation at fair value on the date granted to employees and recognize the compensation expense in the financial statements over the requisite service period. Forfeitures are recorded as they occur. All stock-based compensation expense is recorded using the straight-line method and is included in “General and administrative expenses” in our Consolidated Statements of Income and Comprehensive Income (Loss). 48 Fair value of all the options outstanding was measured using the Black-Scholes model. Determining the appropriate fair value model and calculating the fair value of options requires the input of highly subjective assumptions, including the expected volatility of the price of our stock, the risk-free rate, the expected term of the options, and the expected dividend yield of our common stock. These estimates involve inherent uncertainties and the application of management’s judgment. If factors change and different assumptions are used, our stock-based compensation expense could be materially different in the future. The Black-Scholes option pricing model requires estimates of key assumptions based on both historical information and management judgment regarding market factors and trends. Expected Life – The expected term of stock options represents the period the stock options are expected to remain outstanding and is based on the simplified method, which is the weighted average vesting term plus the original contractual term, divided by two. Expected Volatility – We develop our expected volatility based upon a weighted average volatility of our peer group. Risk-free Interest Rate – The risk-free interest rates for options granted are based on the average of five year and seven year constant maturity Treasury bond rates whose term is consistent with the expected term of an option from the date of grant. Expected Term – The expected term is based on the midpoint between the vesting date and contractual term of an option. The expected term represents the period that our stock-based awards are expected to be outstanding. Expected Dividend Yield – We do not anticipate paying cash dividends on our shares of common stock; therefore, the expected dividend yield is assumed to be zero. Fair value of the stock-based compensation for all of the performance share units as well as performance cash awards outstanding was measured using a Monte Carlo simulation model. Recent Accounting Pronouncements For additional information on recent accounting pronouncements, see Note 2 – Significant Accounting Policies included in Item 8 of Part II of this Annual Report. Emerging Growth Company Status We are an “emerging growth company” as defined in the JOBS Act. Under Section 107 of the JOBS Act, as an emerging growth company, we are taking advantage of an extended transition period for the adoption of new or revised financial accounting standards, including the reduced reporting requirements and exemptions, and the longer phase-in periods for the adoption of new or revised financial accounting standards, until we are no longer an emerging growth company. Our election to use the longer phase-in periods permitted by this election may make it difficult to compare our financial statements to those of non-emerging growth companies and other emerging growth companies that have opted out of the longer phase-in periods under Section 107 of the JOBS Act and who will comply with new or revised financial accounting standards. If we were to subsequently elect instead to comply with these public company effective dates, such election would be irrevocable pursuant to Section 107 of the JOBS Act. Smaller Reporting Company Status We are a “smaller reporting company” as defined by the SEC. As such, we are eligible to comply with the scaled disclosure requirements in several Regulation S-K and Regulation S-X items. Our disclosures in this Annual Report reflect these scaled requirements. 49 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK As a “smaller reporting company,” as defined under the Exchange Act, we are not required to provide the information required by this Item. 50 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Report of Independent Registered Public Accounting Firm (PCAOB ID 238) Consolidated Balance Sheets as of December 31, 2022 and 2021 Consolidated Statements of Income and Comprehensive Income (Loss) for the Years Ended December 31, 2022 and 2021 Consolidated Statements of Stockholders’ Equity (Deficit) for the Years Ended December 31, 2022 and 2021 Consolidated Statements of Cash Flows for the Years Ended December 31, 2022 and 2021 Notes to Consolidated Financial Statements F-1 F-2 F-3 F-4 F-5 F-6 51 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Stockholders of Nine Energy Service, Inc. OPINION ON THE FINANCIAL STATEMENTS We have audited the accompanying consolidated balance sheets of Nine Energy Service, Inc. and its subsidiaries (the “Company”) as of December 31, 2022 and 2021, and the related consolidated statements of income and comprehensive income (loss), consolidated statements of stockholders’ equity (deficit), and consolidated statements of cash flows for the years then ended, including the related notes (collectively referred to as 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 the years then ended in conformity with accounting principles generally accepted in the United States of America. BASIS FOR OPINION These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s 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 of these consolidated financial statements 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. /s/ PricewaterhouseCoopers LLP Houston, TX March 7, 2023 We have served as the Company’s auditor since 2011. F-1 NINE ENERGY SERVICE, INC. CONSOLIDATED BALANCE SHEETS (In thousands, except share and per share amounts) Assets Current assets Cash and cash equivalents Accounts receivable, net Income taxes receivable Inventories, net Prepaid expenses and other current assets Total current assets Property and equipment, net Operating lease right of use assets, net Finance lease right of use assets, net Intangible assets, net Other long-term assets Total assets Liabilities and Stockholders’ Equity (Deficit) Current liabilities Accounts payable Accrued expenses Current portion of long-term debt Current portion of operating lease obligations Current portion of finance lease obligations Total current liabilities Long-term liabilities Long-term debt Long-term operating lease obligations Long-term finance lease obligations Other long-term liabilities Total liabilities Commitments and contingencies (Note 12) Stockholders’ equity (deficit) Common stock (120,000,000 shares authorized at $0.01 par value; 33,221,266 and 32,826,325 shares issued and outstanding at December 31, 2022 and 2021 respectively) Additional paid-in capital Accumulated other comprehensive loss Accumulated deficit Total stockholders’ equity (deficit) Total liabilities and stockholders’ equity (deficit) December 31, 2022 2021 $ 17,445 105,277 741 62,045 11,217 196,725 89,717 36,336 547 101,945 1,564 $ 426,834 $ 21,509 64,025 1,393 42,180 10,195 139,302 86,958 35,117 1,445 116,408 2,383 $ 381,613 $ 42,211 28,391 2,267 7,956 178 81,003 $ 28,680 18,519 2,093 6,091 1,070 56,453 338,031 29,370 — 1,937 450,341 332,314 30,435 65 1,613 420,880 332 775,006 (4,828) (794,017) (23,507) $ 426,834 328 773,350 (4,535) (808,410) (39,267) $ 381,613 The accompanying notes are an integral part of these consolidated financial statements. F-2 NINE ENERGY SERVICE, INC. CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (LOSS) (In thousands, except share and per share amounts) Revenues Service Product Cost and expenses Cost of revenues (exclusive of depreciation and amortization shown separately below) Service Product General and administrative expenses Depreciation Amortization of intangibles Loss on revaluation of contingent liability Loss on sale of property and equipment Income (loss) from operations Interest expense Interest income Gain on extinguishment of debt Other income Income (loss) before income taxes Provision (benefit) for income taxes Net income (loss) Earnings (loss) per share Basic Diluted Weighted average shares outstanding Basic Diluted Other comprehensive loss, net of tax Foreign currency translation adjustments, net of $0 tax in each period Total other comprehensive loss, net of tax Total comprehensive income (loss) Year Ended December 31, 2022 2021 $ $ 455,364 138,018 593,382 248,618 100,801 349,419 350,733 106,360 51,653 26,784 13,463 454 367 43,568 32,486 (305) (2,843) (709) 14,939 546 14,393 0.47 0.45 $ $ $ 228,290 79,702 45,301 28,905 16,116 460 660 (50,015) 32,527 (26) (17,618) (298) (64,600) (25) (64,575) (2.13) (2.13) $ $ $ 30,930,890 32,251,398 30,302,925 30,302,925 $ $ (293) (293) 14,100 $ $ (34) (34) (64,609) The accompanying notes are an integral part of these consolidated financial statements. F-3 NINE ENERGY SERVICE, INC. CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT) (In thousands, except share amounts) Common Stock Shares Amounts Additional Paid-in Capital Accumulated Other Comprehensive Income (Loss) Retained Earnings (Accumulated Deficit) Total Stockholders’ Equity (Deficit) Stockholders’ equity (deficit) as of December 31, 2020 31,557,809 $316 $768,429 $(4,501) $(743,835) $ 20,409 Issuance of common stock under stock compensation plan, net of forfeitures Stock-based compensation expense Vesting of restricted stock and stock units Other comprehensive loss Net loss Stockholders’ equity (deficit) as of December 31, 1,457,626 — (189,110) — — 14 — (2) — — (14) 5,406 (471) — — — — — (34) — — — — — (64,575) — 5,406 (473) (34) (64,575) 2021 32,826,325 $328 $773,350 $(4,535) $(808,410) $(39,267) Issuance of common stock under stock compensation plan, net of forfeitures Stock-based compensation expense Vesting of restricted stock and stock units Other comprehensive loss Net income Stockholders’ equity (deficit) as of December 31, 623,328 — (228,387) — — 7 — (3) — — (7) 2,440 (777) — — — — — (293) — — — — — 14,393 — 2,440 (780) (293) 14,393 2022 33,221,266 $332 $775,006 $(4,828) $(794,017) $(23,507) The accompanying notes are an integral part of these consolidated financial statements. F-4 NINE ENERGY SERVICE, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands) Cash flows from operating activities Net income (loss) Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities Year Ended December 31, 2022 2021 $ 14,393 $(64,575) Depreciation Amortization of intangibles Amortization of operating leases Amortization of deferred financing costs Recovery for doubtful accounts Provision for inventory obsolescence Stock-based compensation expense Gain on extinguishment of debt Loss on sale of property and equipment Loss on revaluation of contingent liability Abandonment of in-process research and development Changes in operating assets and liabilities Accounts receivable, net Inventories, net Prepaid expenses and other current assets Accounts payable and accrued expenses Income taxes receivable/payable Other assets and liabilities Net cash provided by (used in) operating activities Cash flows from investing activities Proceeds from sales of property and equipment Proceeds from property and equipment casualty losses Purchases of property and equipment Net cash used in investing activities Cash flows from financing activities Proceeds from ABL Credit Facility Payments on ABL Credit Facility Purchases of 2023 Notes Payments on Magnum Promissory Notes Proceeds from short-term debt Payments of short-term debt Payments on finance leases Payments of contingent liability Vesting of restricted stock and stock units Net cash provided by financing activities Impact of foreign currency exchange on cash Net decrease in cash and cash equivalents Cash and cash equivalents Cash and cash equivalents at beginning of period Cash and cash equivalents at end of period Supplemental disclosures of cash flow information: Cash paid for interest Cash refunded for income taxes Supplemental schedule of non-cash activities: Capital expenditures in accounts payable and accrued expenses Receivable from property and equipment sale (including insurance) The accompanying notes are an integral part of these consolidated financial statements. 26,784 13,463 8,670 2,545 (166) 2,966 2,440 (2,843) 367 454 1,000 (41,114) (22,968) (818) 19,476 655 (8,632) 16,672 2,959 175 (28,551) (25,417) 24,000 (7,000) (10,081) (1,125) 4,086 (2,787) (1,269) (195) (780) 4,849 (168) (4,064) 28,905 16,116 8,020 2,602 (229) 4,831 5,406 (17,618) 660 460 — (22,540) (8,608) 3,350 12,447 — (9,643) (40,416) 3,492 — (15,413) (11,921) 15,000 — (8,355) (844) 1,513 (545) (1,094) (154) (473) 5,048 (66) (47,355) 21,509 $ 17,445 68,864 $ 21,509 $ 29,708 116 $ $ 30,085 24 $ $ 3,443 701 $ $ $ 63 497 F-5 NINE ENERGY SERVICE, INC. NOTES TO THE FINANCIAL STATEMENTS 1. COMPANY AND ORGANIZATION COMPANY DESCRIPTION Nine Energy Service, Inc. (the “Company” or “Nine”), a Delaware corporation, is an oilfield services business that provides services integral to the completion of unconventional wells through a full range of tools and methodologies. The Company is headquartered in Houston, Texas. The Company’s chief operating decision maker, which is its Chief Executive Officer, and its board of directors allocate resources and assess performance based on financial information presented at a consolidated level. Accordingly, the Company determined that it operates as one reportable segment, known as Completion Solutions. RISKS AND UNCERTAINTIES The Company’s business depends, to a significant extent, on the level of unconventional resource development activity and corresponding capital spending of oil and natural gas companies. These activity and spending levels are strongly influenced by the current and expected oil and natural gas prices. Following an extreme decline in activity levels and pricing in 2020, the Company has been focused on strategically implementing price increases and gaining market share. In 2022, oil and natural gas prices improved, and activity levels increased compared to 2021, resulting in higher demand for the Company’s products and services. Due to a heightened competition for qualified labor, an under-supply of equipment, and other supply chain-related constraints, the Company implemented price increases in most service lines. Finding and retaining qualified labor continues to be a challenge resulting in wage inflation, offsetting some of the price increases. Going forward, the Company’s earnings will be affected by its customers’ activity plans (which are strongly influenced by commodity prices), the Company’s ability to implement further price increases, the impact of wage and labor inflation, and labor shortage and supply chain constraints. Additionally, activity levels could be affected as oilfield service providers continue to raise prices and customers are impacted by cost inflation to drill, complete, and produce oil and natural gas wells. 2. SIGNIFICANT ACCOUNTING POLICIES BASIS OF PRESENTATION The accompanying consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). PRINCIPLES OF CONSOLIDATION The consolidated financial statements as of December 31, 2022 and 2021, and for the years ended December 31, 2022 and 2021, include the accounts of Nine and its wholly owned subsidiaries. All inter-company balances and transactions have been eliminated in the consolidation. USE OF ESTIMATES The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. These estimates are based on management’s best knowledge of current events and actions that the Company may undertake in the future. Such estimates include fair value assumptions used in analyzing long-lived assets for possible impairment, useful lives used in depreciation and amortization expense, recognition of provisions for contingencies, and stock-based compensation fair value. It is at least reasonably possible that the estimates used will change within the next year. F-6 REVENUE RECOGNITION The Company recognizes revenue under Accounting Standards Codification Topic 606 (“ASC 606”) when products are received by a customer’s domestic common carrier at the Company’s facility or when the product is received by the customer’s international carrier. The Company believes this recognition policy reflects the point at which the customer obtains control of the product as required by ASC 606. PERFORMANCE OBLIGATIONS A performance obligation is a promise in a contract to transfer a distinct good or service to the customer and is the unit of account in ASC 606. A contract’s transaction price is allocated to each distinct performance obligation and recognized as revenue when, or as, the performance obligation is satisfied. The Company excludes sales taxes, value added taxes, and other taxes it collects concurrent with revenue-producing activities from revenue. The Company’s revenue is derived from the sale of products and services which are sold directly to customers or are consumed by customers on their well sites. For domestic product sales, the Company typically recognizes revenue when it meets its performance obligation upon the shipment of the products from its facilities to its customer. For international product sales, the Company typically recognizes revenue when it meets its performance obligation upon receipt of the products by the customer’s international carrier. The Company recognizes service revenue over the time the service is performed as the customer consumes and benefits from the use of the Company’s products and services for well service. Service revenues represent revenue recognized over time, as the Company’s customer arrangements typically provide agreed upon hourly or daily fixed-rates, and the Company recognizes service revenue based upon the number of hours or days services have been performed. Contracts for the Company’s products and services are negotiated on a per-job basis at a regional level. Contracts vary in nature but typically have a duration of less than a month and have a single performance obligation either for a job, a series of distinct jobs, or a period the Company stands ready to provide its services to its client as needed. The Company’s payment terms vary by the type and location of its customers and type of product and service offered. The Company receives cash equal to the invoice amount for most services and product sales, and payment terms typically range from 30 to 60 days from the date the Company invoices a customer. Since the period between the delivery of the Company’s products and services and the Company’s receipt of customer payment for these products and services is not expected to exceed one year, the Company has elected not to calculate or disclose a financing component for its customer contracts. CONTRACT ESTIMATES The Company receives reimbursements from its customers for the purchase of supplies, equipment, personnel services, and other services provided at a customer’s request. Reimbursable revenues are subject to uncertainty as the timing of the receipt of these amounts is dependent on factors outside of the Company’s influence. Accordingly, these revenues are not recognized until the uncertainty is resolved, which typically occurs when the related costs are incurred on behalf of the customer. The Company is considered a principal in these transactions and records the associated revenues at the gross amount billed to the customer. Changes and modifications to contracts are routine in the performance of the Company’s contracts due to the dynamic nature of well operations and the services the Company provides for its customers. The Company considers contract modifications to exist when the modification either creates a new contract or changes the existing enforceable rights and obligations of a contract. Most of the Company’s contract modifications are for services or goods that are not distinct from existing contracts due to the significant integration provided or significant interdependencies in the context of the contract and are accounted for as if they were part of the original contract. CONTRACT BALANCES Any contract assets are included in “Accounts receivable, net” in the Company’s Consolidated Balance Sheets. Contract assets arise when recorded revenues for a contract exceed the amounts billed under the terms of the F-7 contracts. The Company classifies contract liabilities as unearned income which is included in “Accrued expenses” in the Company’s Consolidated Balance Sheets. Such deferred revenue typically results from advance payments received on well service orders prior to performance of the service. For information regarding the Company’s revenue, see Note 3 – Revenues. LEASES The Company determines if an arrangement is a lease at inception. To the extent an arrangement represents a lease, the Company classifies that lease as an operating lease or a finance lease under Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842) and its related ASUs (“ASC 842”). The Company capitalizes operating leases on its Consolidated Balance Sheets through a Right of Use (“ROU”) asset and a corresponding lease liability. ROU assets represent the Company’s right to use an underlying asset for the lease term, and lease liabilities represent the Company’s obligation to make lease payments arising from the operating lease. Operating lease ROU assets and obligations are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term utilizing an interest rate that the Company would have incurred to borrow over a similar term the funds necessary to purchase the leased asset. Operating leases are included in “Operating lease right of use assets, net,” “Current portion of operating lease obligations,” and “Long-term operating lease obligations” in the Company’s Consolidated Balance Sheets as of December 31, 2022 and 2021. Lease expense for operating leases is recognized on a straight-line basis over the lease term for 2022 and 2021. Finance leases are included in the line items “Finance lease right of use assets, net,” “Current portion of finance lease obligations,” and “Long-term finance lease obligations” in the Company’s Consolidated Balance Sheets as of December 31, 2022 and 2021. For additional information regarding the Company’s leases, see Note 6 – Leases. CASH AND CASH EQUIVALENTS The Company considers all highly liquid debt instruments with a maturity of three months or less when purchased to be cash equivalents. Throughout the year, the Company maintained cash balances that were in excess of their federally insured limits. The Company has not experienced any losses in such accounts. Cash flows from the Company’s Canadian subsidiary are calculated based on its functional currency. As a result, amounts related to changes in assets and liabilities reported in the Company’s Consolidated Statements of Cash Flows will not necessarily agree to changes in the corresponding balances in the Company’s Consolidated Balance Sheets. FOREIGN CURRENCY The Company’s functional currency is the United States Dollar (“USD”). The financial position and results of operations of the Company’s Canadian subsidiary are measured using the local currency as the functional currency. Revenues and expenses of the subsidiary have been translated into USD at average exchange rates prevailing during the period. Assets and liabilities have been translated at the rates of exchange on the date of the Company’s Consolidated Balance Sheets. The resulting translation gain and loss adjustments have been recorded as a separate component of other comprehensive income (loss) in the Company’s Consolidated Statements of Income and Comprehensive Income (Loss) and its Consolidated Statements of Stockholders’ Equity (Deficit). ACCOUNTS RECEIVABLE The Company extends credit to customers in the normal course of business. Accounts receivable are carried at their estimated collectible amount. Trade credit is generally extended on a short-term basis; thus, receivables do not bear interest, although a finance charge may be applied to amounts past due. The Company maintains an allowance for doubtful accounts for estimated losses that may result from the inability of its customers to make required F-8 payments. Such allowances are based upon several factors including, but not limited to, credit approval practices, industry and customer historical experience, as well as the current and projected financial condition of the specific customer. Accounts receivable outstanding longer than contractual terms are considered past due. The Company writes off accounts receivable to the allowance for doubtful accounts when they become uncollectible. Any payments subsequently received on receivables previously written off are credited to bad debt expense. The Company had $105.3 million and $64.0 million of “Accounts receivable, net” at December 31, 2022 and 2021, respectively. The Company maintains an allowance for doubtful accounts based on the expected collectability of accounts receivable, which is included in “Accounts receivable, net” on the Company’s Consolidated Balance Sheets. The Company had an allowance for doubtful accounts of $0.2 million and $2.8 million at December 31, 2022 and 2021, respectively. Bad debt expense recovery was $0.2 million for both the years ended December 31, 2022 and 2021. CONCENTRATION OF CREDIT RISK The Company derives a significant portion of its revenues from companies in the exploration and production (“E&P”) industry, and its customer base includes a broad range of integrated and independent domestic E&P companies and international E&P companies operating in the markets that the Company serves. While current energy prices are important contributors to positive cash flow for the customers, expectations about future prices and price volatility are generally more important for determining future spending levels. Any prolonged increase or decrease in oil and natural gas prices affects the levels of exploration, development, and production activity as well as the entire health of the oil and natural gas industry and can therefore negatively impact spending by the Company’s customers. No customer accounted for more than 10% of the revenues for the years ended December 31, 2022 and 2021. CONCENTRATION OF SUPPLIER RISK Purchases during the years ended December 31, 2022 and 2021 did not include purchases from any supplier that individually represented more than 10% of total operating purchases. PROPERTY AND EQUIPMENT Property and equipment is stated at cost and depreciated under the straight-line method over the estimated useful lives of the assets. Equipment held under capital leases is stated at the present value of its future minimum lease payments and is depreciated under the straight-line method over the shorter of the lease term or the estimated useful life of the asset. When assets are retired or otherwise disposed of, the cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is recognized within operating expenses. Normal repair and maintenance costs are charged to operating expense as incurred. Significant renewals and betterments are capitalized. VALUATION OF LONG-LIVED ASSETS Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. In performing the review for impairment, future cash flows expected to result from the use of the asset and its eventual disposal are estimated. If the undiscounted future cash flows are less than the carrying amount of the assets, there is an indication that the asset may be impaired. The amount of the impairment is measured as the difference between the carrying value and the Level 3 fair value of the asset. The Level 3 fair value is determined either through the use of an external valuation, or by means of an analysis of discounted future cash flows based on expected utilization. Determining fair value requires the use of estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating profit margins, weighted average costs of capital, terminal growth rates, future market share, the impact of new product development, and future market conditions, among others. The Company believes that the estimates and assumptions used in impairment assessments are reasonable and appropriate. Impairment losses are reflected in “Income (loss) from operations” in the Company’s Consolidated Statements of Income and Comprehensive Income (Loss). F-9 VALUATION OF INTANGIBLE ASSETS Intangible assets with definite lives include technology, customer relationships, and non-compete agreements. The Level 3 fair value of technology and the Level 3 fair value of customer relationships are estimated using the income approach, specifically the multi-period excess earnings method. The multi-period excess earnings method consists of isolating the cash flows attributed to the intangible asset, which are then discounted to present value to calculate the Level 3 fair value of the intangible asset. The Level 3 fair value of non-compete agreements is estimated using a with and without scenario where cash flows are projected through the term of the non-compete agreement assuming the non-compete agreement is in place and compared to cash flows assuming the non-compete agreement is not in place. Intangible assets with definite lives are amortized based on the estimated consumption of the economic benefit over their estimated useful lives. Intangible assets with definite lives are tested for impairment whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. Intangible assets with indefinite useful lives are not subject to amortization. For intangible assets with indefinite useful lives, an assessment for impairment is performed annually on December 31 or when there is an indication an impairment may have occurred. Intangible assets with indefinite useful lives are reviewed for impairment by comparing the carrying value of the intangible asset to the Level 3 fair value of the intangible asset. The Level 3 fair value of intangible assets with indefinite useful lives is estimated using the relief-from-royalty method of the income approach. This approach is based on the assumption that in lieu of ownership, a company would be willing to pay a royalty in order to exploit the related benefits of this intangible asset. Determining fair value requires the use of estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating profit margins, royalty rates, weighted average costs of capital, terminal growth rates, future market share, the impact of new product development, and future market conditions, among others. The Company believe that the estimates and assumptions used in impairment assessments are reasonable and appropriate. The Company recognizes an indefinite-lived intangible asset impairment charge of the amount by which the carrying value of the intangible asset exceeds the Level 3 fair value of the intangible asset. Impairment losses are reflected in “Income (loss) from operations” in the Company’s Consolidated Statements of Income and Comprehensive Income (Loss). STOCK-BASED COMPENSATION The Company has stock-based compensation plans for certain of its employees. The Company measures employee stock-based compensation awards at fair value on the date they are granted to employees and recognizes compensation cost in its financial statements over the requisite service period. As a result of the adoption of ASU No. 2016-09, the Company elected to account for stock-based compensation forfeitures as they occur. RESTRICTED STOCK AND RESTRICTED STOCK UNITS Compensation expense is recorded for restricted stock and restricted stock units over the applicable vesting period based on the Company’s closing stock price as of the grant date. PERFORMANCE STOCK UNITS AND PERFORMANCE CASH AWARDS Performance stock units and performance cash awards are recorded at their fair value and expensed over their performance period. Fair value for performance stock units and performance cash awards is measured using a Monte Carlo simulation model. F-10 OPTIONS Options are issued with an exercise price equal to the fair value of the stock on the date of grant. Compensation expense is recorded for the fair value of the stock options and is recognized over the period of the underlying security’s vesting schedule. Consideration paid on the exercise of stock options is credited to share capital and additional paid-in capital. For options, fair value of the stock-based compensation is measured by use of the Black- Scholes pricing model. The following discusses the assumptions used related to the Black-Scholes pricing model. • The expected term of stock options represents the period the stock options are expected to remain outstanding and is based on the simplified method, which is the weighted average vesting term plus the original contractual term, divided by two. • Expected volatility measures the amount that a stock price has fluctuated or is expected to fluctuate during a period. The Company developed its expected volatility based upon a weighted average volatility of its peer group. • At the time of the issuance of the options, the Company did not plan to pay cash dividends in the foreseeable future. Therefore, a zero expected dividend yield was used in the valuation model. • The risk-free interest rate is based on U.S. Treasury zero-coupon issues with remaining terms similar to the expected term on the options. INCOME TAXES The Company accounts for income taxes under Accounting Standards Codification 740, Income Taxes (“ASC 740”). Under this method, deferred income tax assets and liabilities are determined based upon temporary differences between the carrying amounts and tax bases of the Company’s assets and liabilities at the balance sheet date and are measured using enacted tax rates and laws that will be in effect when the differences are expected to reverse. The effect on deferred tax assets and liabilities of a change in the tax rates is recognized in income in the period in which the change occurs. The Company records a valuation reserve in each reporting period when management believes that it is more likely than not that any deferred tax asset created will not be realized. The Company recognizes the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. If a tax position meets the “more likely than not” recognition criteria, the tax position is measured at the largest amount of benefit greater than 50% likely of being realized upon ultimate settlement. FAIR VALUE OF FINANCIAL INSTRUMENTS The carrying amounts for financial instruments classified as current assets and current liabilities approximate fair value, due to the short maturity of such instruments. For financial assets and liabilities disclosed at fair value, fair value is determined as the exit price, or the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The established fair value hierarchy divides fair value measurement into three levels: • Level 1 – inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date; • Level 2 – inputs other than quoted prices included within Level 1 that are observable for the assets or liability, either directly or indirectly; and • Level 3 – inputs are unobservable for the asset or liability, which reflect the best judgment of management. Financial assets and liabilities that are disclosed at fair value are categorized in one of the above three levels based on the lowest level input that is significant to the fair value measurement in its entirety. Level 1 provides the most reliable measure of fair value, whereas Level 3 generally requires significant management judgment. The fair value of the Company’s debt obligations is classified as Level 2 in the fair value hierarchy and is established based on observable inputs in less active markets. For additional information on the fair value of the Company’s debt obligations, see Note 9 – Debt Obligations. F-11 The fair value of the Company’s contingent consideration is classified as Level 3 in the fair value hierarchy and is established on unobservable markets which reflect the best judgment of management. For additional information on the fair value of the Company’s contingent consideration, see Note 12 – Commitments and Contingencies. EARNINGS (LOSS) PER SHARE Basic earnings (loss) per share is calculated by dividing net income (loss) by the weighted average number of common shares outstanding during the period. Diluted earnings (loss) per share is calculated by dividing net income (loss) by the weighted average number of common shares outstanding during the period, taking into effect, if any, the exercise of potentially dilutive stock options assumed to be purchased from the proceeds using the average market price of the Company’s stock for each of the periods presented as well as potentially dilutive restricted stock, restricted stock units, and performance stock units. There was no dilutive effect for the year ended December 31, 2021 as the Company was in a net loss position. For additional information on earnings (loss) per share, see Note 14 – Earnings (Loss) Per Share. ACCOUNTING PRONOUNCEMENTS RECENTLY ADOPTED In December 2019, the Financial Accounting Standards Board (the “FASB”) issued ASU 2019-12, Income Taxes: Simplifying the Accounting for Income Taxes, which is intended to simplify various aspects related to accounting for income taxes. ASU 2019-12 removes certain exceptions to the general principles and clarifies and amends existing guidance to improve consistent application. ASU 2019-12 is effective for public businesses for fiscal years beginning after December 15, 2020 and interim periods within those fiscal years. As an emerging growth company, the Company is permitted, and adopted, the new standard for fiscal years beginning after December 15, 2021 and interim periods within fiscal years beginning after December 15, 2022. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements included in this Annual Report. ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. ASU 2016-13 requires a financial asset (or a group of financial assets) measured at amortized cost basis to be presented at the net amount expected to be collected. The amendments in ASU 2016-13 replace the current incurred loss impairment methodology in current GAAP with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information. ASU 2016-13 is effective for Securities and Exchange Commission filers, excluding smaller reporting companies, for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. As an emerging growth company, the Company is permitted, and plans, to adopt the new standard for the fiscal years beginning after December 15, 2022, including interim periods within those fiscal years. The Company does not expect the standard to have a material impact on its financial position, results of operations, or liquidity. 3. REVENUES DISAGGREGATION OF REVENUES Disaggregated revenue for the years ended December 31, 2022 and 2021 was as follows: Cement Tools Wireline Coiled tubing Total revenues Year Ended December 31, 2022 2021 (in thousands) $229,409 138,018 107,352 118,603 $593,382 $114,181 100,801 72,436 62,001 $349,419 The Company recognizes revenues from the sales of products at a point in time and revenues from the sales of services over time. F-12 PERFORMANCE OBLIGATIONS At December 31, 2022 and December 31, 2021, the amount of remaining performance obligations was not material. CONTRACT BALANCES At December 31, 2022 and December 31, 2021, contract assets and contract liabilities were not material. 4. INVENTORIES Inventories, consisting primarily of finished goods and raw materials, are stated at the lower of cost or net realizable value. Cost is determined on an average cost basis. The Company reviews its inventory balances and writes down its inventory for estimated obsolescence or excess inventory equal to the difference between the cost of inventory and the estimated market value based upon assumptions about future demand and market conditions. The reserve for obsolescence was $6.7 million and $9.0 million at December 31, 2022 and 2021, respectively. Inventories, net as of December 31, 2022 and 2021 were comprised of the following: Raw materials Work in progress Finished goods Inventories Reserve for obsolescence Inventories, net 5. PROPERTY AND EQUIPMENT Property and equipment amounts as of December 31, 2022 and 2021 were as follows: December 31, 2022 2021 (in thousands) $39,249 161 29,345 68,755 (6,710) $62,045 $31,153 675 19,323 51,151 (8,971) $42,180 Operating equipment Autos and trucks Furniture, fixtures, and equipment Shop equipment Buildings Leasehold improvements Land Less: Accumulated depreciation Property and equipment, net Estimated Useful Lives 1 to 12 years 1 to 7 years 2 to 12 years 3 to 15 years 7 to 39 years 3 to 11 years indefinite December 31, 2022 2021 (in thousands) $ 321,315 4,140 3,843 14,552 4,599 2,017 1,348 351,814 (262,097) $ 89,717 $ 299,602 4,168 4,059 14,555 8,994 1,443 828 333,649 (246,691) $ 86,958 Depreciation expense was $26.8 million and $28.9 million for the years ended December 31, 2022 and 2021, respectively. 6. LEASES Under ASC 842, the Company determines if an arrangement is a lease at inception. Leases with an initial term of 12 months or less are not recorded in the Company’s Consolidated Balance Sheets. Lease with an initial term F-13 greater than 12 months are recognized in the Company’s Consolidated Balance Sheets based on lease classification as either operating or financing. Some of the Company’s lease agreements include lease and non-lease components for which the Company has elected to not separate for all classes of underlying assets. The Company’s lease agreements do not contain any material residual value guarantees or material restrictive covenants. The Company may sublease its real estate to third parties, subject to certain provision of the lease, when it has no future use for the property. OPERATING LEASES As a lessee, the Company’s operating lease portfolio primarily consists of operating leases for equipment, vehicles, office space, yard facilities, and employee housing. Operating lease ROU assets and operating lease obligations are recognized based on the present value of the future minimum lease payments at commencement date. As most of the Company’s leases do not provide an implicit borrowing rate, the Company uses its incremental borrowing rate based on the lease information available at the commencement date in determining the present value of future payments. The incremental borrowing rate utilized is based upon the interest rate associated with the Company’s ABL Credit Facility (as defined and described in Note 9 – Debt Obligations) which is utilized to fund its working capital needs and planned capital expenditures. The Company’s leases have remaining terms of one to ten years and may include options to extend or terminate the lease. The operating lease ROU assets also include any upfront lease payments made and exclude lease incentives and initial direct costs incurred. The Company leases most of these properties under long-term (greater than one year) non-cancelable term leases many of which contain renewal options that can extend the lease term from one to five years and some of which contain escalation clauses. The Company may also enter into short-term or month-to-month operating leases. Options to renew these leases are generally not considered reasonably certain to be exercised due to the nature of the Company’s operations and the markets it serves. Therefore, the periods covered by such optional periods are not included in the determination of the term of the lease. The Company also leases supplemental equipment, typically under cancellable short-term contracts which are less than 30 days. This equipment is typically required for a specific project and for a short duration. Due to the nature of the Company’s operations, any option to renew these short-term leases is generally not considered reasonably certain to be exercised. Therefore, the periods covered by such optional periods are not included in the determination of the term of the lease, and the lease payments during these periods are similarly excluded from the calculation of operating lease asset and lease obligation balances. Operating lease expense consists of rent expense related to leases that were included in ROU assets under ASC 842. The Company recognizes operating lease expense on a straight-line basis, except for certain variable expenses that are recognized when the variability is resolved, typically during the period in which they are paid. Variable operating lease payments typically include charges for property taxes and insurance, and some leases contain variable payments related to non-lease components, including common area maintenance and usage of facilities or office equipment (for example, copiers). The Company does not have variable expenses. F-14 ADDITIONAL INFORMATION The following table summarizes the components of the Company’s lease expense recognized for the years ended December 31, 2022 and 2021, excluding variable lease and prepaid rent costs: Operating lease expense Operating lease right of use assets Operating lease non right of use assets Total operating lease expense Finance lease expense Depreciation of right of use assets Interest on lease obligations Total finance lease expense Year Ended December 31, 2022 2021 (in thousands) $ 8,670 7,697 $16,367 $ 8,020 6,201 $14,221 $ $ 385 199 584 $ $ 399 162 561 Operating lease expense is included in the line items “Cost of revenues” and “General and administrative expenses” in the Company’s Consolidated Statements of Income and Comprehensive Income (Loss) for the years ended December 31, 2022 and 2021. Supplemental information related to leases was as follows as of December 31, 2022 and 2021: Operating leases Weighted average remaining lease term Weighted average discount rate Finance leases Weighted average remaining lease term Weighted average discount rate December 31, 2022 2021 6.4 5.3 5.0% 5.0% 0.4 1.0 21.7% 9.8% Supplemental balance sheet information related to leases was as follows as of December 31, 2022 and 2021: Operating lease right of use assets Operating lease right of use assets, gross Less: Accumulated amortization Operating lease right of use assets, net Operating lease obligations Current portion of operating lease obligations Long-term operating lease obligations Total operating lease obligations Finance lease right of use assets Finance lease right of use assets, gross Less: Accumulated depreciation Finance lease right of use assets, net Finance lease obligations Current portion of finance lease obligations Long-term finance lease obligations Total finance lease obligations December 31, 2022 2021 (in thousands) $ 52,947 (16,611) $ 36,336 $ 45,853 (10,736) $ 35,117 $ 7,956 29,370 $ 37,326 $ 6,091 30,435 $ 36,526 $ 1,057 (510) 547 $ $ 2,980 (1,535) $ 1,445 $ $ 178 — 178 $ 1,070 65 $ 1,135 F-15 Future annual minimum lease payments as of December 31, 2022 were as follows: 2023 2024 2025 2026 2027 Thereafter Total lease payments Less: present value discount Present value of lease obligations Operating Lease Right of Use Obligations Finance Leases Total $ 9,599 7,994 7,047 6,474 5,130 6,243 $42,487 (5,161) $37,326 (in thousands) $219 — — — — — $219 (41) $178 $ 9,818 7,994 7,047 6,474 5,130 6,243 $42,706 (5,202) $37,504 Supplemental cash flow information related to leases for the years ended December 31, 2022 and 2021 were as follows: Cash paid for amounts included in the measurement of lease obligations: Operating cash flows from operating leases Operating cash flows from finance leases Financing cash flows from finance leases Right of use assets obtained in exchange for lease obligations: Operating leases Finance leases 7. INTANGIBLE ASSETS Year Ended December 31, 2021 2022 (in thousands) $8,698 $ 385 $1,269 $8,124 $ 399 $1,094 $8,356 $ 336 $5,059 28 $ The gross carrying amount and accumulated amortization of intangible assets as of December 31, 2022 and 2021 were as follows: Customer relationships Non-compete agreements Technology Total Customer relationships Non-compete agreements Technology In-process research and development Total December 31, 2022 Gross Carrying Amount Accumulated Amortization Net Carrying Amount Weighted Average Amortization Period (in thousands, except weighted average amortization period information) $ 63,270 6,500 125,110 $194,880 $(49,845) (6,166) (36,924) $(92,935) $ 13,425 334 88,186 $101,945 December 31, 2021 4.8 0.8 10.7 Gross Carrying Amount Accumulated Amortization Net Carrying Amount Weighted Average Amortization Period (in thousands, except weighted average amortization period information) $ 63,270 6,500 125,110 1,000 $195,880 $(45,187) (5,766) (28,519) — $(79,472) $ 18,083 734 96,591 1,000 $116,408 5.3 2.0 11.7 Indefinite The Company abandoned its “E-Set” tools business and related $1.0 million in-process research and development indefinite-lived intangible asset in the fourth quarter of 2022. F-16 Amortization of Intangibles Amortization of intangibles was $13.5 million and $16.1 million for the years ended December 31, 2022 and 2021, respectively. Future estimated amortization of intangibles is as follows: Year Ending December 31, 2023 2024 2025 2026 2027 Thereafter 8. ACCRUED EXPENSES Accrued expenses as of December 31, 2022 and 2021 consisted of the following: Accrued interest Accrued compensation and benefits Accrued bonus Accrued legal fees and settlements Other accrued expenses Accrued expenses 9. DEBT OBLIGATIONS The Company’s debt obligations as of December 31, 2022 and 2021 were as follows: 2023 Notes (1) ABL Credit Facility (1) Magnum Promissory Notes (2) Other short-term debt (2) Total debt before deferred financing costs Deferred financing costs Total debt Less: Current portion of long-term debt Long-term debt (in thousands) $ 11,516 11,183 11,183 11,082 10,315 46,666 $ 101,945 December 31, 2021 2022 (in thousands) 5,012 10,283 3,979 145 8,972 $28,391 4,980 6,897 1,125 1,076 4,441 $18,519 December 31, 2022 2021 (in thousands) $307,339 32,000 — 2,267 $341,606 (1,308) $340,298 (2,267) $338,031 $320,343 15,000 1,125 968 $337,436 (3,029) $334,407 (2,093) $332,314 (1) (2) Subsequent to December 31, 2022, the Company redeemed all of the outstanding 2023 Notes and extended the maturity date of the ABL Credit Facility from October 25, 2023 to January 29, 2027. As such, these obligations are classified as long-term on the Company’s Consolidated Balance Sheet at December 31, 2022. Refer to further disclosure within this footnote for additional information. The weighted average interest rate on short-term debt outstanding at December 31, 2022 and 2021, respectively, was 6.0% and 5.1%. 2023 Notes On October 25, 2018, the Company issued $400.0 million principal amount of 8.750% Senior Notes due 2023 (the “2023 Notes”). The 2023 Notes were issued under an indenture, dated as of October 25, 2018 (the “2023 F-17 Notes Indenture”), by and among the Company, certain subsidiaries of the Company and Wells Fargo, National Association, as Trustee. The 2023 Notes bore interest at an annual rate of 8.750% payable on May 1 and November 1 of each year, commencing May 1, 2019. The 2023 Notes were senior unsecured obligations of the Company and were fully and unconditionally guaranteed on a senior unsecured basis by each of the Company’s current domestic subsidiaries and by certain future subsidiaries. The 2023 Notes Indenture contained covenants that limited the Company’s ability and the ability of its restricted subsidiaries to engage in certain activities. The Company was in compliance with the provisions of the 2023 Notes Indenture at December 31, 2022. Pursuant to the 2023 Notes Indenture, upon an event of default, the trustee or the holders of at least 25% in aggregate principal amount of then outstanding 2023 Notes may declare the 2023 Notes immediately due and payable, except that a default resulting from certain events of bankruptcy or insolvency with respect to the Company, any significant subsidiary or any group of subsidiaries that, taken together, would constitute a significant subsidiary, would automatically cause all outstanding 2023 Notes to become due and payable. Unamortized deferred financing costs associated with the 2023 Notes were $1.3 million and $3.0 million at December 31, 2022 and 2021, respectively. These costs were direct deductions from the carrying amount of the 2023 Notes and were amortized through interest expense through the maturity date of the 2023 Notes using the effective interest method. Extinguishment of Debt The Company repurchased approximately $13.0 million of 2023 Notes at a repurchase price of approximately $10.1 million in cash for the year ended December 31, 2022. Deferred financing costs associated with these transactions were $0.1 million for the year ended December 31, 2022. As a result, for the year ended December 31, 2022, the Company recorded a $2.8 million gain on the extinguishment of debt, which was calculated as the difference between the repurchase price and the carrying amount of the 2023 Notes partially offset by the deferred financing costs. The Company repurchased approximately $26.3 million of 2023 Notes at a repurchase price of approximately $8.4 million in cash for the year ended December 31, 2021. Deferred financing costs associated with these transactions were $0.3 million for the year ended December 31, 2021. As a result, for the year ended December 31, 2021, the Company recorded a $17.6 million gain on the extinguishment of debt, which was calculated as the difference between the repurchase price and the carrying amount of the 2023 Notes partially offset by the deferred financing costs. The gain on extinguishment of debt is included as a separate line item in the Company’s Consolidated Statements of Income and Comprehensive Income (Loss) for the years ended December 31, 2022 and 2021. Redemption On February 1, 2023, with proceeds received from its public offering of Units (as defined and described below) and borrowings under its ABL Credit Facility (as defined and described below), the Company redeemed all of the outstanding 2023 Notes at a redemption price of 100.0% of outstanding principal amount thereof ($307.3 million), plus accrued and unpaid interest ($6.7 million). The Company also wrote off the unamortized deferred financing costs associated with the 2023 Notes in conjunction with the redemption. UNITS OFFERING AND 2028 NOTES Units On January 30, 2023, the Company completed its public offering of 300,000 units with an aggregate stated amount of $300.0 million (the “Units”). Each Unit consists of $1,000 principal amount of the Company’s 13.000% Senior Secured Notes due 2028 (collectively, the “2028 Notes”) and five shares of common stock of the Company. The Company received proceeds of $279.8 million from the Units offering, after deducting underwriting discounts and commission, which was used to fund a portion of the redemption price of the 2023 Notes. F-18 Each Unit will be separated into its constituent securities (the 2028 Notes and shares of the Company’s common stock) automatically on October 27, 2023, or, if earlier, on the date, if any, on which a change of control or event of default (each as defined in the indenture governing the 2028 Notes) occurs. A holder of Units may elect to separate its Units into its constituent securities, in whole but not in part, on or after March 31, 2023. Prior to such date, the Units may not be separated at the option of the holder. Once a Unit has been separated into its constituent securities at the option of a holder, it cannot be recreated. Prior to separating the Units into its constituent securities, a holder thereof will not be able to participate in any redemption or repurchase of the 2028 Notes, and holders of the 2028 Notes must have separated their Units prior to the date of any redemption of any offer to repurchase commencement date in order to participate in such redemption or repurchase. Holders of Units are entitled to the rights of a holder of the Company’s common stock, including, without limitation, the right to vote and consent to or receive notice as a stockholder. 2028 Notes On January 30, 2023, the Company and certain of its subsidiaries entered into an indenture, dated as of January 30, 2023 (the “2028 Notes Indenture”), with U.S. Bank Trust Company, National Association, as the trustee and as notes collateral agent, pursuant to which the 2028 Notes, which form a part of the Units, were issued. The 2028 Notes will mature on February 1, 2028 and bear interest at an annual rate of 13.000% payable in cash semi-annually in arrears on each of February 1 and August 1, commencing August 1, 2023. The 2028 Notes are senior secured obligations of the Company and are guaranteed on a senior secured basis by each of the Company’s current domestic subsidiaries and by certain future subsidiaries, subject to agreed guaranty and security principles and certain exclusions. Prior to February 1, 2026, the Company may, on any one or more occasions, redeem all or a part of the 2028 Notes at a redemption price equal to 100.0% of the principal amount of the 2028 Notes redeemed, plus a “make- whole” premium, plus accrued and unpaid interest, if any, to, but excluding, the date of redemption. In addition, prior to February 1, 2026, the Company may, from time to time, redeem up to 35.0% of the aggregate principal amount of the 2028 Notes with an amount of cash not greater than the net cash proceeds of certain equity offerings at a redemption price equal to 113.0% of the principal amount of the 2028 Notes redeemed, plus accrued and unpaid interest, if any, to, but excluding, the date of redemption, provided that at least 65.0% of the aggregate principal amount of the 2028 Notes issued under the 2028 Notes Indenture remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. Also, prior to February 1, 2026, the Company may redeem during each 12-month period beginning on January 30, 2023, up to 10% of the principal amount of the 2028 Notes on a redemption price equal to 103.0% of the aggregate principal amount of the 2028 Notes being redeemed, plus accrued and unpaid interest, if any, to, but excluding, the date of redemption. On and after February 1, 2026, the Company may redeem the 2028 Notes, in whole or in part, at the redemption prices (expressed as percentages of principal amount of the 2028 Notes to be redeemed) set forth below, plus accrued and unpaid interest, if any, to, but excluding the date of redemption, if redeemed during the periods indicated: February 1, 2026 to January 31, 2027 February 1, 2027 to October 31, 2027 November 1, 2027 and thereafter Redemption Price 106.500% 103.250% 100.000% On each May 15 and November 14, commencing November 14, 2023 (each, an “Excess Cash Flow Offer Date”), the Company is required to make an offer (an “Excess Cash Flow Offer”) to all holders of the 2028 Notes and, if required by the terms of any Pari Passu Notes Lien Indebtedness (as defined in the 2028 Notes Indenture), to any holders of any Pari Passu Notes Lien Indebtedness to purchase, prepay or redeem, together on a pro-rata basis, the maximum principal amount of the 2028 Notes and any such Pari Passu Notes Lien Indebtedness (plus all F-19 accrued interest (including additional interest, if any) on the 2028 Notes and any such Pari Passu Notes Lien Indebtedness and the amount of all fees and expenses, including premiums, incurred in connection therewith) that may be purchased, prepaid or redeemed using an amount of cash equal to the Excess Cash Flow Amount (as defined in the 2028 Notes Indenture and which is 75.0% of Excess Cash Flow (as defined in the 2028 Notes Indenture), as determined immediately prior to the Excess Cash Flow Offer Date), if any, subject to certain exceptions set forth in the 2028 Notes Indenture. The offer price in any such offer will be equal to 100% of the principal amount of the 2028 Notes and any such Pari Passu Notes Lien Indebtedness (or, in respect of any such Pari Passu Notes Lien Indebtedness, such lesser price, if any, as may be provided for by the terms of such Pari Passu Notes Lien Indebtedness), plus accrued and unpaid interest and additional interest, if any, to, but excluding, the date of purchase, prepayment or redemption, subject to the rights of holders of the 2028 Notes or any such Pari Passu Notes Lien Indebtedness on the relevant record date to receive interest due on an interest payment date that is on or prior to the date of purchase, prepayment or redemption, and will be payable in cash. If the Company experiences certain changes of control, each holder of 2028 Notes may require the Company to repurchase all or a portion of its 2028 Notes for cash at a price equal to 101.0% of the principal amount of such 2028 Notes, plus any accrued but unpaid interest, if any, to, but excluding, the date of repurchase. The 2028 Notes Indenture contains covenants that, among other things and subject to certain exceptions and qualifications, limit the Company’s ability and the ability of its restricted subsidiaries to (i) incur additional indebtedness and guarantee indebtedness; (ii) pay dividends or make other distributions of capital stock; (iii) prepay, redeem or repurchase certain debt; (iv) issue certain preferred stock or similar equity securities, (v) make loans and investments; (vi) sell assets; (vii) incur liens; (viii) enter into transactions with affiliates; (ix) enter into agreements restricting its subsidiaries’ ability to pay dividends; or (x) consolidate, merge, or sell all or substantially all of its assets. Upon an event of default, the trustee of the 2028 Notes or the holders of at least 25% in aggregate principal amount of then outstanding 2028 Notes may declare the 2028 Notes immediately due and payable, except that a default resulting from certain events of bankruptcy or insolvency with respect to the Company, any significant subsidiary or any group of restricted subsidiaries that, taken together, would constitute a significant subsidiary, will automatically cause all outstanding 2028 Notes to become due and payable. ABL CREDIT FACILITY Background On October 25, 2018, the Company entered into a credit agreement dated as of October 25, 2018 (the “2018 ABL Credit Agreement”), by and among the Company, Nine Energy Canada, Inc., JP Morgan Chase Bank, N.A. as administrative agent and as an issuing lender, and certain other financial institutions party thereto as lenders and issuing lenders. The 2018 ABL Credit Agreement permitted aggregate borrowings of up to $200.0 million, subject to a borrowing base, including a Canadian tranche with a sub-limit of up to $25.0 million and a sub-limit of $50.0 million for letters of credit (the “ABL Credit Facility”). Pursuant to the 2018 ABL Credit Agreement, the ABL Credit Facility was set to mature on October 25, 2023 or, if earlier, on the date that is 180 days before the scheduled maturity date of the 2023 Notes if they had not been redeemed or repurchased by such date. Pursuant to the 2018 ABL Credit Agreement, loans to the Company and its domestic related subsidiaries (the “U.S. Credit Parties”) under the ABL Credit Facility were base rate loans or London Interbank Offered Rate (“LIBOR”) loans; and loans to Nine Energy Canada Inc., a corporation organized under the laws of Alberta, Canada, and its restricted subsidiaries (the “Canadian Credit Parties”) under the Canadian tranche may be Canadian Dollar Offered Rate (“CDOR”) loans or Canadian prime rate loans. The applicable margin for base rate loans and Canadian prime rate loans varied from 0.75% to 1.25% and the applicable margin for LIBOR loans or CDOR loans varied from 1.75% to 2.25%, in each depending on the Company’s leverage ratio. In addition, a commitment fee of 0.50% per annum was charged on the average daily unused portion of the revolving commitments. On January 17, 2023, the Company entered into the First Amendment to Credit Agreement (the “ABL Facility Amendment”) with JP Morgan Chase Bank, N.A., as administrative agent, and the lender parties thereto, which amends certain terms of the 2018 ABL Credit Agreement (as amended the “ABL Credit Agreement”). The ABL Facility Amendment became effective on January 30, 2023. F-20 Pursuant to the ABL Facility Amendment, the maturity date of the ABL Credit Facility was extended from October 25, 2023 to January 29, 2027. In addition, the ABL Facility Amendment, among other changes, revised the terms of the ABL Credit Facility as follows: (a) decreased the size of the ABL Credit Facility from $200.0 million to $150.0 million, subject to the borrowing base, (b) changed the interest rate benchmark from LIBOR to Term Secured Overnight Financing Rate with a 10 basis point spread adjustment and increased pricing from the existing range of 1.75% to 2.25% to a range of 2.00% to 2.50%, in each case depending on the Company’s leverage ratio, (c) modified the financial covenant, enhanced reporting and cash dominion triggers in the ABL Credit Facility from the existing minimum availability threshold of the greater of $18.75 million and 12.5% of the loan limit to a minimum availability threshold of (i) $12.5 million from January 30, 2023 until May 31, 2023 and (ii) the greater of $17.5 million and 12.5% of the loan limit thereafter, (d) decreased the Canadian tranche sub-limit from $25.0 million to $5.0 million, (e) decreased the letter of credit sub-limit from $50.0 million to $10.0 million and (f) made satisfaction of the Payment Conditions (as defined in the ABL Facility Amendment) a condition to an Excess Cash Flow Offer in addition to a condition to voluntary payments of the 2028 Notes. The Payment Conditions in summary are (A) no default or event of default on a pro forma basis and (B) immediately after and at all times and at all times during the 30 days prior, on a pro forma basis, (1) (x) availability under the ABL Credit Facility shall not be less than the greater of 15% of the loan limit and $22.5 million and (y) the fixed charge coverage ratio shall be at least 1.00 to 1.00 or (2) availability under the ABL Credit Facility shall not be less than the greater of 20% of the loan limit and $30.0 million. The 2018 ABL Credit Agreement contained and the ABL Credit Agreement contains, various affirmative and negative covenants, including financial reporting requirements and limitations on indebtedness, liens, mergers, consolidations, liquidations and dissolutions, sales of assets, dividends and other restricted payments, investments (including acquisitions), and transactions with affiliates. In addition, the 2018 ABL Credit Agreement contained a minimum fixed charge ratio covenant of 1.00 to 1.00 that was tested quarterly when the availability under the ABL Credit Facility dropped below $18.75 million or a default has occurred until the availability exceeds such threshold for 30 consecutive days and such default is no longer outstanding. The Company was in compliance with all covenants under the 2018 ABL Credit Agreement as of December 31, 2022. Pursuant to the 2018 ABL Credit Agreement, all of the obligations under the ABL Credit Facility were, and pursuant to the ABL Credit Agreement, all of the obligations under the ABL Credit Facility are secured by security interests (subject to permitted liens) in substantially all of the personal property of U.S. Credit Parties, excluding certain assets. The obligations under the Canadian tranche are further secured by security interests (subject to permitted liens) in substantially all of the personal property of Canadian Credit Parties, excluding certain assets. At December 31, 2022, the Company had $32.0 million outstanding borrowings under the ABL Credit Facility, and its availability under the ABL Credit Facility was approximately $66.6 million, net of outstanding letters of credit of $1.3 million. On January 27, 2023, the Company borrowed an additional $40.0 million under the ABL Credit Facility to pay for the redemption price of the 2023 Notes and to pay for fees and expenses related to the Units offering. Both the ABL Credit Facility and the Units collateralization were completed within 30 days after closing in accordance with the terms of the ABL Facility Amendment and the Units offering. MAGNUM PROMISSORY NOTES On October 25, 2018, pursuant to the terms of a Securities Purchase Agreement, dated October 15, 2018 (as amended on June 7, 2019, the “Magnum Purchase Agreement”), the Company acquired all of the equity interests of Magnum Oil Tools International, LTD, Magnum Oil Tools GP, LLC, and Magnum Oil Tools Canada Ltd. (such entities collectively, “Magnum”). The Magnum Purchase Agreement included the potential for additional future payments in cash of (i) up to 60% of net income (before interest, taxes, and certain gains or losses) for the “E-Set” tools business in 2019 through 2026 and (ii) up to $25.0 million based on sales of certain dissolvable plug products in 2019 (the “Magnum Earnout”). F-21 On June 30, 2020, pursuant to an amendment to the Magnum Purchase Agreement to terminate the remaining Magnum Earnout and all obligations related thereto, the Company issued promissory notes with an aggregated principal amount of $2.3 million (the “Magnum Promissory Notes”) to the sellers of Magnum. The Magnum Promissory Notes bear interest at a rate of 6.0% per annum. The principal amount of the Magnum Promissory Notes was paid in equal quarterly installments which began January 1, 2021. The remaining outstanding balance was paid on October 1, 2022. OTHER SHORT-TERM DEBT In the fourth quarter of 2022, the Company renewed certain insurance policies, and it financed the premium for its excess policy in the amount of $4.1 million. At December 31, 2022, the outstanding balance on this premium was $2.3 million. FAIR VALUE OF DEBT INSTRUMENTS The estimated fair value of the Company’s debt obligations as of December 31, 2022 and 2021 was as follows: December 31, 2022 2021 (in thousands) 2023 Notes ABL Credit Facility Magnum Promissory Notes Other short-term debt $300,700 $ 32,000 $ $ 2,267 — $ $ $153,765 $ 15,000 1,125 968 The fair value of the 2023 Notes, ABL Credit Facility, the Magnum Promissory Notes, and other short-term debt is classified as Level 2 in the fair value hierarchy. The fair value of the 2023 Notes is established based on observable inputs in less active markets. The fair value of the ABL Credit Facility, the Magnum Promissory Notes, and other short-term debt approximates their carrying value. 10. DEFINED CONTRIBUTION PLANS BACKGROUND The Company sponsors a defined contribution plan, the Nine Energy Service 401(k) Plan (the “Nine Plan”), under Section 401(k) of the Internal Revenue Code of 1986, as amended, for all qualified employees. CONTRIBUTIONS For the years ended December 31, 2022 and 2021, the Company made no employer contributions under the Nine Plan. F-22 11. STOCK-BASED COMPENSATION STOCK OPTIONS Information about stock option activity during the years ended December 31, 2022 and 2021 was as follows: 2022 Activity Beginning balance Granted Exercised Forfeited Expired Total outstanding Options exercisable 2021 Activity Beginning balance Granted Exercised Forfeited Expired Total outstanding Options exercisable Number of Shares in Underlying Options Weighted Average Exercise Price Remaining Weighted Average Contractual Life in Years 610,410 — — — (22,904) 587,506 587,506 $33.52 — — — 26.28 $33.80 $33.80 3.9 — — — — 3.0 3.0 Number of Shares in Underlying Options Weighted Average Exercise Price Remaining Weighted Average Contractual Life in Years 702,542 — — — (92,132) 610,410 610,410 $32.63 — — — 26.71 $33.52 $33.52 4.5 — — — — 3.9 3.9 Intrinsic Value (in thousands) $— — — — — $— $— Intrinsic Value (in thousands) $— — — — — $— $— The intrinsic value at December 31, 2022 and 2021 is the amount by which the fair value of the underlying share exceeds the exercise price of an option as of December 31, 2022 and 2021, respectively. The Company granted no options in 2022 and 2021. There was no compensation expense recorded for the years ended December 31, 2022 and 2021. As of December 31, 2022, there is no remaining compensation expense related to options for the Company to expense. Future stock option grants will result in additional compensation expense. Restricted Stock and Restricted Stock Units Information about restricted stock and restricted stock unit activity during the years ended December 31, 2022 and 2021 was as follows: 2022 Activity Nonvested at January 1, 2022 Granted Vested Forfeited Nonvested at December 31, 2022 Number of Shares and Units 2,379,320 651,250 (1,068,092) (27,922) 1,934,556 Weighted Average Grant Date Fair Value $ 2.83 2.80 4.13 2.02 $ 2.12 F-23 2021 Activity Nonvested at January 1, 2021 Granted Vested Forfeited Nonvested at December 31, 2021 Number of Shares and Units 1,714,398 1,509,000 (792,704) (51,374) 2,379,320 Weighted Average Grant Date Fair Value $ 6.69 2.15 9.77 4.33 $ 2.83 The total amount of compensation expense related to the restricted stock and restricted stock units recorded was approximately $2.4 million and $4.9 million for the years ended December 31, 2022 and 2021, respectively. As of December 31, 2022, the Company expects to record compensation expense related to restricted stock and restricted stock units of approximately $3.0 million over the remaining term of approximately 1.9 years. Future restricted stock and restricted stock unit grants would result in additional compensation expense. Performance Stock Units The Company granted performance stock units (“PSUs”) in 2019. The number of PSUs that vested in the first quarter of 2022 was contingent upon the Company’s achievement of certain specified targets. These awards had market conditions and were valued using a Monte Carlo simulation model. The volatility of 49.7% was developed based upon the historical volatility of the Company as well as the volatilities of a group of peer companies, as the Company’s trading history needed to be supplemented with additional data as it went public in 2018. The risk-free rate, which was derived using the U.S. Treasury security rates at the grant date, was 2.44%. Nonvested at January 1, Granted (1) Vested Forfeited Nonvested at December 31, 2022 2021 61,900 — (42,714) (19,186) 61,900 — — — — 61,900 (1) The Company granted PSUs in 2019 that vested in the first quarter of 2022 contingent upon the Company’s achievement of certain specified targets based on a three-year performance period ending December 31, 2021. The nonvested PSU balance at January 1, 2021 is shown at target level. The Company did not grant PSUs in 2022 or 2021. There was no compensation expense related to PSUs for the year ended December 31, 2022, and for the year ended December 31, 2021, the total amount of compensation expense related to PSUs was approximately $0.5 million. As of December 31, 2022, the Company has no further compensation expense related to PSUs to record. Future PSU grants will result in additional compensation expense. Performance Cash Awards In May 2022, the Company granted performance cash awards (the “PCAs”) that vest based upon the Company’s achievement of certain criteria related to its relative total shareholder return (“TSR”) in comparison to TSR of members of its peer group (the “Peer Group”), as defined by the PCA grant. These awards, which the Company granted at a target achievement amount, are subject to three individual year-long performance periods (the “Performance Periods”), and payment related to each Performance Period can range from 0% to 200% of the target amount for that Performance Period. The PCAs were valued on the date of grant based on the estimated fair value, which was based on numerous assumptions including the likelihood of the Company’s stock price performance achieving targeted thresholds, using a Monte Carlo simulation model. The assumptions used to value the awards included the historical volatility F-24 of the Company as well as the volatility of its Peer Group and the risk-free rate, which was derived using the U.S. Treasury security rates. Under the relevant liability accounting, the fair values for each tranche of the PCAs are remeasured at the end of each reporting period. At December 31, 2022, the volatility for remeasurement was 123.82%, and the risk-free rate was 4.30%. Compensation expense related to PCAs for the year ended December 31, 2022 was approximately $1.8 million. As of December 31, 2022, based upon the valuation of the PCAs at year end, the Company had remaining compensation expense to recognize of $1.6 million. Future PCA grants will result in additional compensation expense. 12. COMMITMENTS AND CONTINGENCIES LITIGATION The Company records accruals related to litigation and other legal proceedings when they are either known or considered probable and can be reasonably estimated. Legal proceedings are inherently unpredictable and subject to significant uncertainties, and significant judgment is required to determine both probability and the estimated amount. Some of these uncertainties include the stage of litigation, available facts, uncertainty as to the outcome of any legal proceedings or settlement discussions, and any novel legal issues presented. Because of such uncertainties, accruals are based on the best information available at the time. As additional information becomes available, the Company reassesses the potential liability related to pending litigation. As of December 31, 2022 and 2021, the Company recorded a $0.1 million and a $1.1 million accrual, respectively, for liabilities related to legal matters, which is included under the caption “Accrued expenses” in its Consolidated Balance Sheets. From time to time, the Company has various claims, lawsuits, and administrative proceedings that are pending or threatened with respect to personal injury, workers’ compensation, contractual matters, and other matters. Although no assurance can be given with respect to the outcome of these claims, lawsuits, or proceedings or the effect such outcomes may have, the Company believes any ultimate liability resulting from the outcome of such claims, lawsuits, or administrative proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on its business, operating results, or financial condition. SELF-INSURANCE The Company uses a combination of third-party insurance and self-insurance for health insurance claims. The self-insured liability represents an estimate of the undiscounted ultimate cost of uninsured claims incurred as of the balance sheet date. The estimate is based on an analysis of trailing months of incurred medical claims to project the amount of incurred but not reported claims liability. The estimated liability for self-insured medical claims was $1.2 million and $1.0 million at December 31, 2022 and 2021, respectively, and is included under the caption “Accrued expenses” on the Company’s Consolidated Balance Sheets. Although the Company does not expect the amounts ultimately paid to differ significantly from the estimates, the self-insurance liability could be affected if future claims experience differs significantly from historical trends and actuarial assumptions. CONTINGENT LIABILITIES On October 1, 2018, pursuant to the terms and conditions of a Securities Purchase Agreement (“the Frac Tech Purchase Agreement”), the Company acquired Frac Technology AS, a Norwegian private limited company (“Frac Tech”) focused on the development of downhole technology, including a casing flotation tool and a number of patented downhole completion tools. The Frac Tech Purchase Agreement, as amended, includes, among other things, the potential for additional future payments, based on certain Frac Tech revenue metrics through December 31, 2025. F-25 The Company’s contingent liability (Level 3) for the years ended December 31, 2022 and 2021 was as follows: Balance at December 31, 2020 Payments Revaluation adjustments Balance at December 31, 2021 Payments Revaluation adjustments Balance at December 31, 2022 Frac Tech (in thousands) $ 604 (154) 460 $ 910 (195) 454 $1,169 All contingent liabilities that relate to contingent consideration are reported at fair value, based on a Monte Carlo simulation model. Significant inputs used in the fair value measurement include estimated gross margin related to forecasted sales of the plugs, term of the agreement, and a risk adjusted discount factor. Contingent liabilities include $0.4 million and $0.1 million reported in “Accrued expenses” at December 31, 2022 and 2021, respectively, and $0.8 million reported in “Other long- term liabilities” at both December 31, 2022 and 2021 in the Company’s Consolidated Balance Sheets. The impact of the revaluation adjustments is included in the Company’s Consolidated Statements of Income and Comprehensive Income (Loss). 13. TAXES The components of the provision (benefit) for income taxes for the years ended December 31, 2022 and 2021 were as follows: Current U.S. federal U.S. state Foreign Total current provision (benefit) Deferred U.S. federal U.S. state Foreign Total deferred provision (benefit) Total provision (benefit) for income taxes Year Ended December 31, 2022 2021 (in thousands) $ — 510 36 $ 546 $ — — — — $ 546 $ — (56) 31 $ (25) $ — — — — $ (25) The provision (benefit) for income taxes for the years ended December 31, 2022 and 2021 differed from the provision (benefit) calculated using the applicable statutory federal income tax rate as follows: Tax provision (benefit) at statutory rate Foreign rate differential State income taxes, net of federal benefit Nondeductible expenses Valuation allowance Non-cash compensation Other Total provision (benefit) for income taxes F-26 Year Ended December 31, 2022 2021 (in thousands) $ 3,137 (16) 403 912 (5,823) 1,879 54 546 $ $ (13,570) (41) (44) 413 11,350 1,893 (26) (25) $ The tax effects of the cumulative temporary differences resulting in the net deferred tax asset (liabilities) at December 31, 2022 and 2021 were as follows: Deferred income tax assets: Inventories Goodwill and intangible assets Deferred tax benefit from net losses Stock-based compensation and cash award expense Tax credit carryforwards Accrued expenses Interest carryover Lease liability Other Total deferred income tax assets Less: Valuation allowance Net deferred income tax assets Deferred income tax liabilities: Property and equipment ROU asset Total deferred income tax liabilities Net deferred income tax asset (liability) December 31, 2022 2021 (in thousands) $ 2,298 75,617 79,914 2,524 655 678 13,860 8,441 163 184,150 (162,888) $ 21,262 $ 2,533 83,318 79,690 4,194 695 1,632 6,824 8,162 164 187,212 (170,747) $ 16,465 $ $ (12,974) (8,288) (21,262) $ — $ (8,387) (8,078) (16,465) — As of December 31, 2022, the Company had federal and state net operating loss carryforwards (“NOLs”) of approximately $442.2 million. The federal NOLs related to tax years 2017 and prior can be used for a 20-year period and, if unused, will begin to expire in 2034. The state NOLs can be used from 7 to 20 years and vary by state. A small portion of state NOLs expired in 2022. The Company evaluates its deferred tax assets on a quarterly basis to determine whether a valuation allowance is required. The Company assesses whether a valuation allowance should be established based on its determination of whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible and prior to the expiration of its NOL and tax credit carryforwards. The Company considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Due to recent operating results, the Company continues to be in a three-year cumulative loss position for the year ended December 31, 2022. According to ASC 740, cumulative losses in recent years represent significant negative evidence in considering whether deferred tax assets are realizable. As a result, the Company continues to record a valuation allowance against its U.S. domestic and Canadian deferred tax assets. The 2022 results include a decrease in the Company’s valuation allowance of approximately $7.9 million. If the Company is able to generate sufficient taxable income in the future, and it becomes more likely than not that the Company will be able to fully utilize the net deferred tax assets on which a valuation allowance was recorded, the allowance will be released resulting in a tax benefit. The Company is subject to U.S. federal income tax as well as income tax in multiple state jurisdictions. The earliest period the Company is subject to examination of federal income tax returns by the Internal Revenue Service is 2019. The state income tax returns and other state tax filings of the Company are subject to examination by the state taxing authorities for various periods, generally up to four years after they are filed. F-27 The Company accounts for uncertain tax positions in accordance with guidance in ASC 740, which prescribes the minimum recognition threshold a tax position taken or expected to be taken in a tax return is required to meet before being recognized in the financial statements. A reconciliation of the beginning and ending amount of uncertain tax positions is as follows: Balance at January 1, Additional based on tax positions related to prior years Additional based on tax positions related to current year Reduction based on tax positions related to prior years Lapse of statute of limitations Balance at December 31, 2022 (in thousands) $779 — — — — $779 The total amount of unrecognized tax benefits at December 31, 2022 was $0.8 million. The total balance of unrecognized tax benefit would impact the Company’s future effective income tax rate if recognized. The Company recognizes interest and penalties related to uncertain tax positions within the provision for income taxes in its Consolidated Statements of Income and Comprehensive Income (Loss). As of December 31, 2022, no interest and penalties have been accrued. 14. EARNINGS (LOSS) PER SHARE Basic earnings (loss) per share is computed by dividing net income (loss) by the weighted average number of common shares outstanding for the period. Diluted earnings (loss) per share is based on the weighted average number of shares outstanding during each period and the exercise of potentially dilutive stock options assumed to be purchased from the proceeds using the average market price of the Company’s stock for each of the periods presented as well as the potentially dilutive restricted stock, restricted stock units, and performance stock units. Basic and diluted earnings (loss) per common share was computed as follows: Basic Unvested restricted stock and stock units Diluted Basic Unvested restricted stock and stock units Diluted Year Ended December 31, 2022 Net Income Average Shares Outstanding Earnings Per Share (in thousands, except for share and per share amounts) $14,393 — $14,393 30,930,890 1,320,508 32,251,398 $0.47 — $0.45 Year Ended December 31, 2021 Net Loss Average Shares Outstanding Loss Per Share (in thousands, except for share and per share amounts) $(64,575) — $(64,575) 30,302,925 — 30,302,925 $(2.13) — $(2.13) The diluted earnings (loss) per share calculation excludes all stock options, unvested restricted stock, unvested restricted stock units, and unvested performance stock units for 2021 because there is a net loss for the period, and their inclusion would be anti-dilutive. The average number of securities that were excluded from diluted earnings (loss) per share that would potentially dilute earnings (loss) per share for the period in which the Company experienced a net loss was as follows: Year ended December 31, F-28 2022 2021 — 729,514 15. RELATED PARTY TRANSACTIONS The Company leases office space, yard facilities, and equipment and purchases building maintenance and repair services from entities owned by David Crombie, an executive officer of the Company. Total lease expense and building maintenance and repair expense associated with these entities was $1.3 million and $0.9 million for the years ended December 31, 2022 and 2021, respectively. The Company also purchased $2.6 million of products and services for both the years ended December 31, 2022 and 2021 from an entity in which Mr. Crombie is a limited partner. There were outstanding payables due to this entity relating to equipment purchases of $0.1 million and $0.7 million at December 31, 2022 and 2021, respectively. In addition, the Company currently leases office space in Corpus Christi, Texas and previously leased office space in Midland, Texas from an entity affiliated with Warren Lynn Frazier, a beneficial owner of more than 5% of the Company’s stock. In the third quarter of 2020, another entity affiliated with Mr. Frazier began to sub-lease a portion of such space in Corpus Christi, Texas from the Company. Total rental expense associated with these office spaces, net of sub-leasing income, was $1.6 million and $1.4 million for the years ended December 31, 2022 and 2021, respectively. There were net outstanding payables due to these entities of $0.1 million at December 31, 2022. Additionally, on June 30, 2020, the Company issued the Magnum Promissory Notes to the sellers of Magnum, including Mr. Frazier. At December 31, 2022, there was no outstanding principal balance payable to Mr. Frazier, and the balance payable to Mr. Frazier was $1.1 million at December 31, 2021. For additional information regarding the Magnum Promissory Notes, see Note 9 – Debt Obligations. The Company purchases chemical additives used in cementing from Select Energy Services, Inc. (“Select”). One of the Company’s directors also served as a director of Select from November 2017 to November 2022. The Company was billed $1.5 million and $1.1 million for the years ended December 31, 2022 and 2021, respectively. There were outstanding payables due to Select of $0.1 million at both December 31, 2022 and 2021. The Company provides products and rentals to National Energy Reunited Corp. (“NESR”), where one of the Company’s directors serves as a director. The Company billed NESR $0.8 million and $1.3 million for the years ended December 31, 2022 and 2021, respectively. During the fourth quarter of 2019, the Company sold coiled tubing equipment for $5.9 million to NESR with payments due in 24 monthly equal installments beginning on January 31, 2020. Total outstanding receivables due to the Company from NESR (inclusive of the equipment sale above) were $0.2 million and $0.5 million at December 31, 2022 and 2021, respectively. Ann G. Fox, President and Chief Executive Officer and a director of the Company, is a director of Devon Energy Corporation (“Devon”). The Company generated revenue from Devon of $2.2 million and $3.2 million for the years ended December 31, 2022 and 2021, respectively. There were outstanding receivables due from Devon of $0.5 million and $0.4 million at December 31, 2022 and 2021, respectively. 16. SUPPLEMENTAL INFORMATION Capital expenditures for years ended December 31, 2022 and 2021 were as follows: Completion Solutions Corporate Total assets by segment as of December 31, 2022 and 2021 were as follows: Completion Solutions Corporate Year Ended December 31, 2022 2021 (in thousands) $32,162 105 $32,267 $14,742 15 $14,757 December 31, 2022 2021 (in thousands) $399,546 27,288 $426,834 $349,429 32,184 $381,613 F-29 Revenue by country for the years ended December 31, 2022 and 2021 were as follows: United States Canada Year Ended December 31, 2022 Year Ended December 31, 2021 Amount (in thousands) $591,614 1,768 $593,382 Percentage 99.7% 0.3% 100.0% Amount (in thousands) $347,445 1,974 $349,419 Percentage 99.4% 0.6% 100.0% Long-lived assets (defined as property and equipment and definite-lived intangible assets) by country as of December 31, 2022 and 2021 were as follows: United States Canada and other December 31, 2022 2021 (in thousands) $189,962 1,700 $191,662 $200,227 2,139 $202,366 F-30 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. ITEM 9A. CONTROLS AND PROCEDURES EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES Disclosure controls and procedures are controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer’s management, including its principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure. As required by Rule 13a-15(b) under the Exchange Act, our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2022. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2022. MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act). Our internal control over financial reporting is a process designed under the supervision of our principal executive officer and principal financial officer, and effected by our board of directors, management, and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external purposes in accordance with GAAP. As of December 31, 2022, our management assessed the effectiveness of our internal control over financial reporting based on the criteria for effective internal control over financial reporting established by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control-Integrated Framework (2013). Based on its assessment using the COSO criteria, management has concluded that our internal control over financial reporting was effective as of December 31, 2022. ATTESTATION REPORT OF THE INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM This Annual Report does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting as we are an “emerging growth company” as defined under the JOBS Act. In addition, management’s report on internal control over financial reporting was not subject to attestation by our independent registered public accounting firm pursuant to rules of the SEC that permit us to provide only management’s report in this Annual Report. CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING There have been no changes in our internal control over financial reporting during the quarterly period ended December 31, 2022 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. ITEM 9B. OTHER INFORMATION None. 52 ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS Not applicable. 53 PART III ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE The information required in response to this Item will be set forth in our definitive proxy statement for the 2023 annual meeting of stockholders and is incorporated herein by reference. ITEM 11. EXECUTIVE COMPENSATION The information required in response to this Item will be set forth in our definitive proxy statement for the 2023 annual meeting of stockholders and is incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS The information required in response to this Item will be set forth in our definitive proxy statement for the 2023 annual meeting of stockholders and is incorporated herein by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE The information required in response to this Item will be set forth in our definitive proxy statement for the 2023 annual meeting of stockholders and is incorporated herein by reference. ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES The information required in response to this Item will be set forth in our definitive proxy statement for the 2023 annual meeting of stockholders and is incorporated herein by reference. 54 PART IV ITEM 15. EXHIBIT AND FINANCIAL STATEMENT SCHEDULES (a) Documents Filed as Part of This Annual Report 1. FINANCIAL STATEMENTS The following consolidated financial statements of the Company are filed as a part of this Annual Report: Report of Independent Registered Public Accounting Firm Consolidated Balance Sheets as of December 31, 2022 and 2021 Consolidated Statements of Income and Comprehensive Income (Loss) for the Years Ended December 31, 2022 and 2021 Consolidated Statements of Stockholders’ Equity (Deficit) for the Years Ended December 31, 2022 and 2021 Consolidated Statements of Cash Flows for the Years Ended December 31, 2022 and 2021 Notes to Consolidated Financial Statements F-1 F-2 F-3 F-4 F-5 F-6 2. FINANCIAL STATEMENT SCHEDULES All financial statement schedules have been omitted because they are not applicable, or the required information is presented in the consolidated financial statements and related notes. 3. EXHIBITS The exhibits to this Annual Report required to be filed pursuant to Item 15(b) are listed below. Exhibit Number Description Third Amended and Restated Certificate of Incorporation of Nine Energy Service, Inc., dated January 23, 2018 (Incorporated by reference to Exhibit 3.1 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on January 23, 2018). Fourth Amended and Restated Bylaws of Nine Energy Service, Inc., dated January 23, 2018 (Incorporated by reference to Exhibit 3.2 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on January 23, 2018). Form of Common Stock Certificate (Incorporated by reference to Exhibit 4.1 of Nine Energy Service, Inc.’s Amendment No. 2 to Registration Statement on Form S-1 filed on May 24, 2017). Second Amended and Restated Stockholders Agreement, dated as of February 28, 2017, by and among Nine Energy Service, Inc. and the parties thereto (Incorporated by reference to Exhibit 4.2 of Nine Energy Service, Inc.’s Amendment No. 2 to Registration Statement on Form S-1 filed on May 24, 2017). First Amendment to Second Amended and Restated Stockholders Agreement, dated as of July 24, 2017, by and among Nine Energy Service, Inc. and the parties thereto (Incorporated by reference to Exhibit 4.3 of Nine Energy Service, Inc.’s Amendment No. 3 to Registration Statement on Form S-1 filed on August 14, 2017). Registration Rights Agreement, dated as of October 25, 2018, by and among Nine Energy Service, Inc., the former owners of the equity interests of Magnum Oil Tools International, LTD, Magnum Oil Tools Canada Ltd. and Magnum Oil Tools GP, LLC and the other holders that may become party thereto from time to time (Incorporated by reference to Exhibit 4.2 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on October 26, 2018). Unit Agreement, dated as of January 30, 2023, by and among Nine Energy Service, Inc. and U.S. Bank Trust Company, National Association, as units trustee (including Form of Unit Certificate) (Incorporated by reference to Exhibit 4.1 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on February 1, 2023). Indenture, dated as of January 30, 2023, by and among Nine Energy Service, Inc., the guarantors party thereto and U.S. Bank Trust Company, National Association, as trustee and as notes collateral agent (including Form of Note) (Incorporated by reference to Exhibit 4.2 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on February 1, 2023). Description of Common Stock (Incorporated by reference to Exhibit 4.7 of Nine Energy Service, Inc.’s Annual Report on Form 10-K filed on March 10, 2020). Credit Agreement, dated as of October 25, 2018, by and among Nine Energy Service, Inc., Nine Energy Canada Inc., JPMorgan Chase Bank, N.A. and certain other financial institutions (Incorporated by reference to Exhibit 10.1 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on October 26, 2018). 3.1 3.2 4.1 4.2 4.3 4.4 4.5 4.6 4.7 10.1 55 Exhibit Number 10.2 10.3+ 10.4+ 10.5+ 10.6+ 10.7+ 10.8+ 10.9+ 10.10+ 10.11+ 10.12+ 10.13+ 10.14+ 10.15+ 10.16+ 10.17+ 10.18+ 10.19+ 10.20+ Description First Amendment to Credit Agreement, dated as of January 17, 2023, among Nine Energy Service, Inc., Nine Energy Canada Inc., the guarantors party thereto, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent (Incorporated by reference to Exhibit 10.1 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on January 18, 2023). Form of Indemnification Agreement between Nine Energy Service, Inc. and its directors and certain officers (Incorporated by reference to Exhibit 10.10 of Nine Energy Service, Inc.’s Amendment No. 2 to Registration Statement on Form S-1 filed on May 24, 2017). Nine Energy Service, Inc. 2011 Stock Incentive Plan, as amended and restated effective February 28, 2017 (Incorporated by reference to Exhibit 10.10 of Nine Energy Service, Inc.’s Registration Statement on Form S-1 filed on May 2, 2017). First Amendment to the Nine Energy Service, Inc. 2011 Stock Incentive Plan (Incorporated by reference to Exhibit 10.1 of the Nine Energy Service, Inc.’s Current Report on Form 8-K filed on May 6, 2021). Form of Nine Energy Service, Inc. Restricted Stock Agreement for Executives (Incorporated by reference to Exhibit 10.1 of Nine Energy Service, Inc.’s Quarterly Report on Form 10-Q filed on May 14, 2018). Form of Nine Energy Service, Inc. Nonstatutory Stock Option Agreement for Executives (Incorporated by reference to Exhibit 10.2 of Nine Energy Service, Inc.’s Quarterly Report on Form 10-Q filed on May 14, 2018). Form of Nine Energy Service, Inc. Restricted Stock Agreement for Non-Employee Directors (Incorporated by reference to Exhibit 10.3 of Nine Energy Service, Inc.’s Quarterly Report on Form 10-Q filed on May 14, 2018). Form of Nine Energy Service, Inc. Nonstatutory Stock Option Agreement for Non-Employee Directors (Incorporated by reference to Exhibit 10.4 of Nine Energy Service, Inc.’s Quarterly Report on Form 10-Q filed on May 14, 2018). Form of Nine Energy Service, Inc. Performance Share Unit Grant Notice and Form of Performance Share Unit Agreement (Incorporated by reference to Exhibit 10.1 of Nine Energy Service, Inc.’s Quarterly Report on Form 10-Q filed on May 8, 2019). Form of Nine Energy Service, Inc. Cash Award Grant Notice and Form of Cash Agreement (Incorporated by reference to Exhibit 10.1 of Nine Energy Service, Inc.’s Quarterly Report on Form 10-Q filed on May 5, 2022). Form of Nine Energy Service, Inc. Performance-Based Cash Award Grant Notice and Form of Performance-Based Cash Award Agreement (Incorporated by reference to Exhibit 10.1 of Nine Energy Service, Inc.’s Quarterly Report on Form 10-Q filed on August 4, 2022). Amended and Restated Employment Agreement, dated August 28, 2018, by and between Nine Energy Service, LLC and Ann G. Fox (Incorporated by reference to Exhibit 10.1 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on August 30, 2018). Employment Agreement between Guy Sirkes and Nine Energy Service, LLC, dated as of March 31, 2020 (Incorporated by reference to Exhibit 10.1 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on March 31, 2020). Amended and Restated Employment Agreement between David Crombie and Nine Energy Service, LLC, dated as of November 20, 2018 (Incorporated by reference to Exhibit 10.1 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on November 27, 2018). Amended and Restated Employment Agreement between Theodore R. Moore and Nine Energy Service, LLC, dated as of November 20, 2018 (Incorporated by reference to Exhibit 10.4 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on November 27, 2018). Letter Agreement, effective as of April 1, 2020, between Nine Energy Service, LLC and Ann G. Fox (Incorporated by reference to Exhibit 10.1 of Nine Energy Service, Inc.’s Quarterly Report on Form 10-Q filed on August 7, 2020). Letter Agreement, effective as of April 1, 2020, between Nine Energy Service, LLC and David Crombie (Incorporated by reference to Exhibit 10.2 of Nine Energy Service, Inc.’s Quarterly Report on Form 10-Q filed on August 7, 2020). Letter Agreement, effective as of April 1, 2020, between Nine Energy Service, LLC and Guy Sirkes (Incorporated by reference to Exhibit 10.3 of Nine Energy Service, Inc.’s Quarterly Report on Form 10-Q filed on August 7, 2020). Letter Agreement, effective as of April 1, 2020, between Nine Energy Service, LLC and Theodore R. Moore (Incorporated by reference to Exhibit 10.5 of Nine Energy Service, Inc.’s Quarterly Report on Form 10-Q filed on August 7, 2020). 56 Exhibit Number 21.1* 22.1* 23.1* 31.1* 31.2* 32.1** 32.2** List of Subsidiaries of Nine Energy Service, Inc. Description List of Subsidiary Guarantors and Affiliates Whose Securities Collateralize Securities of Nine Energy Service, Inc. Consent of PricewaterhouseCoopers LLP. Certification by Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Certification by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Certifications by Chief Executive Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002. Certifications by Chief Financial Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002. 101* Interactive Data Files. * ** + Filed herewith. Furnished herewith. Management contract or compensatory plan or arrangement. 57 ITEM 16. FORM 10-K SUMMARY None. 58 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. NINE ENERGY SERVICE, INC. By: /s/ Ann G. Fox Ann G. Fox President and Chief Executive Officer Date: March 7, 2023 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 7, 2023. Title President, Chief Executive Officer, and Director (Principal Executive Officer) Senior Vice President and Chief Financial Officer (Principal Financial Officer) Chief Accounting Officer (Principal Accounting Officer) Chairman of the Board Director Director Director Director Director Director Director Signature /s/ Ann G. Fox Ann G. Fox /s/ Guy Sirkes Guy Sirkes /s/ S. Brett Luz S. Brett Luz /s/ Ernie L. Danner Ernie L. Danner /s/ David C. Baldwin David C. Baldwin /s/ Mark E. Baldwin Mark E. Baldwin Curtis F. Harrell /s/ Scott E. Schwinger Scott E. Schwinger /s/ Gary L. Thomas Gary L. Thomas /s/ Andrew L. Waite Andrew L. Waite /s/ Darryl K. Willis Darryl K. Willis 59 [THIS PAGE INTENTIONALLY LEFT BLANK] [THIS PAGE INTENTIONALLY LEFT BLANK] C O R P O R AT E I N F O R M AT I O N BOARD OF DIRECTORS EXECUTIVE LEADERSHIP GENERAL INFORMATION Ernie Danner Chairman of the Board Ann G. Fox President and Chief Executive Ofﬁcer Ann G. Fox President and Chief Executive Ofﬁcer David Crombie Chief Operating Ofﬁcer and Executive Vice President David Baldwin Partner, SCF Partners Mark E. Baldwin Former Executive Vice President and Chief Financial Ofﬁcer, Dresser-Rand Group, Inc. Guy Sirkes Senior Vice President and Chief Financial Ofﬁcer Ted Moore Senior Vice President and General Counsel Brett Luz Chief Accounting Ofﬁcer Clair Holley Chief Technology Ofﬁcer Heather Schmidt Vice President, Strategic Development, Investor Relations and Marketing Curtis F. Harrell Chief Executive Ofﬁcer, Citation Oil & Gas Corp. Scott Schwinger President, McNair Interests Gary L. Thomas Former President, EOG Resources, Inc. Andrew L. Waite Managing Partner, SCF Partners Darryl Willis Corporate Vice President of Energy Resources, Microsoft Auditors PricewaterhouseCoopers Houston, TX Transfer Agent AST 6201 15th Avenue Brooklyn, NY 11219 help@astﬁnancial.com 800-937-5449 Investor Relations Contact Heather Schmidt 281-730-5100 investors@nineenergyservice.com 2001 Kirby Drive, Suite 200 Houston, TX 77019 Trading Information New York Stock Exchange Ticker Symbol: NINE Headquarters Nine Energy Service, Inc. 2001 Kirby Drive, Suite 200 Houston, TX 77019 281-730-5100 www.nineenergyservice.com COMPARISON OF FIVEYEAR CUMULATIVE TOTAL RETURN* Among Nine Energy Service, Inc., the S&P 500 Index and the PHLX Oil Service Sector Index $250 $200 $150 $100 $50 $0 1 / 19/ 18 3 / 18 6 / 18 9/ 18 12 / 18 Nine Energy Service, Inc. 6 / 19 3 / 19 S&P 500 9/ 19 12 / 19 3 / 20 6 / 20 9/ 20 12 / 20 3 / 21 6 / 21 9/ 21 12 / 21 3 / 22 6 / 22 9/ 22 12 / 22 PHLX Oil Service Sector *$100 invested on 1/19/18 in stock or 12/31/17 in index, including reinvestment of dividends. Fiscal year ending December 31. Copyright© 2023 Standard & Poor’s, a division of S&P Global. All rights reserved.

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