What changed in this filing

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Item 7. Management’s Discussion and Analysis

2022-02-28 compared with 2021-03-01 · 98 added, 87 removed, 149 unchanged (55% of the section changed)

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Risk Factors” included elsewhere in this Annual Report, all of which are difficult to predict.

In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

In light of these risks, uncertainties

and assumptions, the forward-looking events discussed may not occur.

We assume no obligation to update any of these forward-looking statements except as otherwise required by law.

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Year-to-year comparisons of the 2020 financial information to the same information for 2019 are contained in “Item 7.

Management’s Discussion and Analysis of Financial Condition and Result of Operations” of our Annual Report on Form 10-K for the year ended December 31, 2019 filed with the Securities and Exchange Commission on February 28, 2020, which comparative information and the information therein under the caption “Factors Affecting the Comparability of our Financial Condition and Results of Operations” are incorporated by reference herein.

Management’s Discussion and Analysis of Financial Condition and Result of Operations” of our Annual Report on Form 10-K for the year ended December 31, 2020 filed with the Securities and Exchange Commission on March 1, 2021, which comparative information and the information therein under the caption “Factors Affecting the Comparability of our Financial Condition and Results of Operations” are incorporated by reference herein.

Market Factors

Business” for information on our products and business.

Demand for our products and services depends primarily upon the general level of activity in the oil and gas industry, including the number of drilling rigs in operation, the number of oil and gas wells being drilled, the depth and drilling conditions of these wells, the number of well completions, the level of well remediation activity, the volume of production and the corresponding capital spending by oil and natural gas companies.

Oil and gas activity is in turn heavily influenced by, among other factors, oil and gas prices locally and worldwide, which have historically been volatile.

Demand for our products and services depends primarily upon the general level of activity in the oil and gas industry, including the number of drilling rigs in operation, the number of wells being drilled, the depth and working pressure of these wells, the number of well completions, the level of well remediation activity, the volume of production and the corresponding capital spending by oil and natural gas companies.

Oil and gas activity is in turn heavily influenced by, among other factors, investor sentiment, availability of capital and oil and gas prices locally and worldwide, which have historically been volatile.

The key market factors impacting our product sales are the number of wells drilled and placed on production, as each well requires an individual wellhead assembly and, at some time after completion, the installation of an associated production tree.

We measure our product sales activity levels against our competitors by the number of rigs that we are supporting on a monthly basis as it is correlated to wells drilled.

Each active drilling rig produces different levels of revenue based on the customer’s drilling plan, which includes factors such as the number of wells drilled per pad, the time taken to drill each well, the number and size of casing strings, the working pressure, material selection and the complexity of the wellhead system chosen by the customer and the rate at which production trees are eventually deployed.

Each active drilling rig produces different levels of revenue based on the customer’s drilling program and efficiencies, which includes factors such as the number of wells drilled per pad, the time taken to drill each well, the number and size of casing strings, the working pressure, material selection, the complexity of the wellhead system chosen by the customer and the rate at which production trees are eventually deployed.

All of these factors may be influenced by the oil and gas region in which our customer is operating.

While these factors may lead to differing revenues per rig, we are able to broadly forecast our product needs and anticipated revenue levels based on general trends in a given region and with a specific customer.

Increases in horizontal wells drilled as a percentage of total wells drilled, the shift towards pad drilling, and

an increase in the number of wells drilled per rig are all favorable trends that we believe enhance the demand for our products relative to the active rig count.

Our rental revenues are primarily dependent on the number of wells completed (i.e., hydraulically fractured), the number of wells on a well pad and the number of fracture stages per well.

Well completion activity generally follows the level of drilling activity but can be delayed due to such factors as takeaway capacity, storage capacity and budget constraints.

Changes to the number of drilled but uncompleted wells (“DUCs”) could provide additional opportunities or headwinds for our rental business relative to general drilling activity.

While these factors may lead to differing revenues per rig, we have generally been able to forecast our product needs and anticipated revenue levels based on historic trends in a given region and with a specific customer.

Increases in horizontal wells drilled as a percentage of total wells drilled, the shift towards pad drilling, and an increase in the number of wells drilled per rig are all favorable trends that we believe enhance the demand for our products relative to the active rig count.

However, such favorable trends might be adversely affected by overall supply chain-related disruptions.

Our rental revenues are primarily dependent on the number of wells completed (i.e., hydraulically fractured), the number of wells on a well pad, the number of fracture stages per well and the number of fracture stages completed per day.

Well completion activity generally follows the level of drilling activity over time, but can be delayed or accelerated due to such factors as pressure pumping availability, takeaway capacity, storage capacity, spot prices, overall service cost inflation and budget considerations.

Field service and other revenues are closely correlated to revenues from product sales and rentals, as items sold or rented almost always have an associated service component.

Therefore, the market factors and trends of product sales and rental revenues similarly impact the associated levels of service and other revenues generated.

Therefore, the market factors and trends of product sales and rental revenues similarly impact the associated levels of field service and other revenues generated.

Our business experiences some seasonality during the fourth quarter due to holidays and customers managing their budgets as the year closes out.

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Recent Developments and Trends

The ongoing COVID-19 pandemic negatively impacted our business and revenues beginning as early as March 2020.

Throughout 2020, the inability to control the spread of the virus and the recent resurgence in cases globally has resulted in continued travel restrictions, school and business closures and stay-at-home orders worldwide.

Although vaccines have begun to be administered all over the world, until vehicle and airline travel returns to activity levels closer to those prior to the pandemic, demand for oil will continue to be depressed.

Oil prices have recovered from the lows experienced in April 2020, trading above $50 per barrel in January 2021 partially due to Saudi Arabia announcing that it will cut one million barrels a day of crude production starting in February 2021.

As oil began trading above $60 per barrel in mid-February 2021 primarily due to harsh winter weather conditions resulting in production disruptions, there has been increasing speculation that Saudi Arabia will restore production of an incremental one million barrels per day starting in April 2021.

Even with these recent increases in commodity prices, our customers’ activity continues to be significantly lower than 2019 and early 2020 levels, which translates into reduced demand for our products and services.

The resurgence of COVID-19 cases in the United States and other countries as well as delays in vaccinations may limit improvements in the demand for oil and natural gas products and could lead to additional government-mandated lockdowns and other restrictions, which would likely continue to have a negative impact on global energy demand.

During 2020, we saw a significant decline in the level of onshore drilling activity in the U.S.

primarily caused by commodity price weakness compounded by the impacts from the COVID-19 pandemic.

In spite of multiple surges of COVID cases in the United States and worldwide, economies reopened throughout 2021 and global demand for fossil fuels rebounded.

As demand grew and the Organization of Petroleum Exporting Countries Plus (OPEC+) group constrained its production targets, oil prices increased.

West Texas Intermediate (“WTI”) prices exceeded $80 per barrel in October 2021 and January 2022, surpassing $90 per barrel in February 2022.

Natural gas prices also increased significantly in 2021, increasing from an average of $2.59 per one million British Thermal Units (“MMBtu”) in December 2020 to $3.76 per MMBtu in December 2021 after exceeding $5.00 per MMBtu for three months beginning in September 2021.

In January 2022, the U.S.

Energy Information Administration forecasted that natural gas prices are expected to remain near $4.00 per MMBtu in 2022.

These higher commodity prices have resulted in increased drilling and completion activity by customers and improved demand for our products and services which has translated into higher activity and revenues for our business.

In response to increased activity levels, we added almost 400 associates during 2021, reinstated wages and salaries to their full

amounts and restored the 401(k) match and other programs that were suspended or reduced in response to the industry downturn in 2020.

We have also added fleet vehicles in line with headcount additions and invested capital in our rental fleet primarily to use a more environmentally friendly method of powering certain equipment that reduces diesel fuel usage.

Barring significant adverse impacts to fossil fuel demand, including that caused by the Delta variant, Omicron variant, other variants, or the perception thereof, we anticipate continued activity growth in 2022.

On February 24, 2022, Russia launched a “special military operation” and invaded Ukraine.

The assault represents the biggest attack on a European state since World War Two.

In response to news of the attack, WTI exceeded $100 per barrel before falling back down to the $90s range.

Natural gas prices also spiked but not as dramatically as oil as natural gas prices have been high in 2022 due to several powerful winter storms that have impacted the U.S., particularly the Northeast.

Additionally, with the current conflict in Ukraine, Russia has threatened to cut off all natural gas transported into the European Union adding to the volatility and high natural gas prices that began in early February 2022.

The ongoing conflict in Ukraine could have repercussions globally and in the U.S.

by continuing to cause uncertainty, not only in the oil and natural gas markets, but also in the stock market.

Such uncertainty could result in stock price volatility and supply chain disruptions as well as higher oil and natural gas prices which could potentially result in higher inflation worldwide and could negatively impact demand for our goods and services.

The significant increase in commodity prices in 2021 and into early 2022 led to meaningful increases in the level of U.S.

onshore drilling activity, particularly among private operators.

At the end of 2020, the U.S.

onshore rig count as reported by Baker Hughes was 781 rigs.

onshore rig count as reported by Baker Hughes was 332 rigs compared to 570 at the end of 2021.

The weekly average U.S.

onshore rig count for the three months ended December 31, 2020 was 295 rigs, a 63% decline when compared to 796 rigs for the comparable period in 2019.

The increase in commodity prices beginning late in 2020 and into 2021 has led to rebounds in the level of U.S.

onshore drilling activity since bottoming in August of 2020 at 230 rigs.

onshore rig count for the three months ended December 31, 2021 was 543 rigs, an 84% increase when compared to 295 rigs for the comparable period in 2020.

Although these gains are encouraging, current rig activity is still significantly reduced from the levels in 2019 when the weekly average rig count for the three months ended December 31, 2019 was 796.

However, improved rig efficiencies have partially offset the impact of this reduction.

As of February 25, 2022, the U.S.

onshore rig count was 635.

Recently, there has been an increase in large-scale merger and acquisition activity among E&P companies that operate in the United States.

These transactions may be driven in part by an effort to reduce the cost of hydrocarbon production per barrel equivalent and increase overall company efficiencies.

These transactions generally increase the size and scale of the counterparties involved, which may provide better access to capital and lead to a healthier overall industry.

We have historically focused on providing our products and services to large and well capitalized customers.

Consolidation of E&P companies presents both risks and opportunities depending on a number of factors, but namely whether the companies involved are existing customers.

We believe our company is well positioned to continue successfully navigating the challenges posed by the current market environment.

At December 31, 2020, we had no long term debt and a strong balance sheet.

In response to the drop in demand and customer activity in 2020, we had implemented certain workforce, wage and capital expenditure reductions beginning as early as March 2020.

Given the significant service component of our business, we adjust our headcount to reflect current activity levels.

By mid-year 2020, we had reduced our global workforce by approximately 50%.

As demand and activity started showing signs of recovery, we began bringing our associates back and reinstated 145 associates before the end of the year.

We have continued adding personnel in 2021 in line with market activity and implemented a partial roll-back of the wage reductions effective late January 2021.

The magnitude of the partial roll-back is less than half of the wage and salary reductions that were implemented in 2020.

We are cautiously optimistic regarding signs of recovery.

However, we continue to actively review all opportunities to manage costs and efficiently deploy capital relative to market conditions.

Our required capital

expenditures have historically tended to be lower than most other oilfield service providers due to the asset-lite nature of our business model.

Substantially all of the products and frac rental equipment that we import through our Chinese supply chain are subject to tariffs under Section 301 of the Trade Act of 1974 (“Section 301”).

For the year ended December 31, 2020, we estimate that approximately 40% of the items received were sourced through our Chinese supply chain.

In May 2019, the U.S.

Trade Representative announced that it was increasing the level of tariffs on approximately $200 billion worth of Chinese imports pursuant to Section 301.

The tariff rate on covered products that were exported on or after May 10, 2019 was raised from 10% to 25%.

In 2020, we received a temporary exclusion and tariff suspension on certain covered products exported from China to the United States under Section 301 and received refunds totaling $14.2 million, inclusive of $0.5 million in interest, for tariffs paid on excluded products exported after September 24, 2018.

Approximately $4.0 million of the tariff recoveries related to balances included in inventory and were recorded as a reduction to inventory and $9.7 million was recorded as credits to cost of goods sold to offset the accounts where the tariff expenses were originally recorded.

The tariff exemption ended August 7, 2020;

therefore, we have resumed paying tariffs at 25% on the previously excluded parts imported from China.

We believe further increases in the tariff rate above 25% may adversely affect our business, but a combination of factors may mitigate some of the impact of any future increases in tariff rates on our results of operations.

These include, among other things, use of product received prior to the introduction of tariffs, our negotiations with suppliers, use of alternative supply chains and favorable currency exchange movements.

Private E&P companies were responsible for the majority of the rig additions in the U.S.

onshore market in 2021.

We significantly increased our revenues and rigs followed since our recent low in activity in the third quarter of 2020 despite a greater portion of Cactus’ revenues having historically resulted from publicly traded E&P companies.

During this time, Cactus meaningfully increased its business with private E&P companies.

Disproportionate changes in activity from private or publicly traded E&P companies present both risks and opportunities for Cactus, depending on a number of factors, such as which customers add or drop rigs and their relative efficiency in drilling wells.

Increased Costs

While our revenues have benefited from increased demand and activity levels, we have also experienced substantial cost increases beginning in 2021.

Due to COVID-related pressures on the supply chain and significantly increased demand for goods and services worldwide, we have experienced substantial increases in salaries and wages, raw materials and ocean freight costs.

Salaries and wages increased significantly during 2021 as a result of competitive labor markets, especially in certain key oil and gas producing areas, but also due to labor shortages and inflation.

Due to heightened demand and a shortage of steel caused primarily by production disruptions during the pandemic, steel and assembled component prices have been and remain elevated.

Freight costs, specifically ocean freight costs, have also risen significantly due to a number of factors including, but not limited to, a scarcity of shipping containers, congested seaports, a shortage of commercial drivers, capacity constraints on vessels and lockdowns in certain markets.

In addition to dealing with these unprecedented cost increases, we have also been impacted by the global supply chain issues which have, in some cases, resulted in increased costs when we are required to use other more expensive modes of transportation or substitute more costly products in order to meet customer demand.

Although we believe certain cost increases are temporary, we do not believe that commodity and freight prices will normalize until late 2022.

Additionally, we cannot be confident that prices will return to the lower levels experienced in prior years.

These cost increases have already had, and could continue to have, a negative impact on our margins and results of operations absent further cost recovery efforts.

Consolidated Results of Operations

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Income from operations 75,427 70,039 5,388 7.7

Interest income, net 701 879 (178) (20.3)

Interest income (expense), net (774) 701 (1,475) nm

Other income (expense), net 492 (555) 1,047 nm

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nm = not meaningful

Product revenue for the year ended December 31, 2020 was $206.8 million, a decrease of $150.3 million, or 42%, from $357.1 million for the year ended December 31, 2019.

The decrease was primarily due to lower sales of wellhead and production related equipment as our customers reduced their drilling and completion activity for most of 2020 in direct response to the overall industry downturn resulting from depressed commodity prices exacerbated by the COVID-19 pandemic.

Product revenue for the year ended December 31, 2021 was $280.9 million compared to $206.8 million for the year ended December 31, 2020.

The increase of $74.1 million, representing a 36% increase from 2020, was primarily due to higher sales of wellhead and production related equipment resulting from higher drilling and completion activity by our customers compared to 2020 and the impact of cost recovery efforts implemented throughout 2021.

In the prior year, the industry downturn impacted sales for the majority of 2020 due to depressed commodity prices as a result of the pandemic.

Rental revenue for the year ended December 31, 2021 was $61.6 million, a decrease of $4.5 million, or 7%, from $66.2 million for the year ended December 31, 2020.

The decrease was primarily attributable to reduced completion activity by our customers as part of the industry downturn in 2020.

Field service and other revenue for the year ended December 31, 2020 was $75.6 million, a decrease of $53.9 million, or 42%, from $129.5 million for the year ended December 31, 2019.

The decrease was primarily attributable to lower customer activity in 2020 related to the industry downturn, resulting in lower billable hours and ancillary services.

The decrease was primarily due to reduced completion rental activity among our customer base and the extraordinary market pressure driven by depressed energy demand associated with the COVID-19 pandemic.

Recovery in our rental business has been slower than our product business as an excess supply of competing rental equipment relative to demand from customers led to market dynamics that did not justify the deployment of our assets in certain cases.

Field service and other revenue for the year ended December 31, 2021 was $96.1 million, an increase of $20.5 million, or 27%, from $75.6 million for the year ended December 31, 2020.

The increase was attributable to increased customer activity compared to the prior year, resulting in higher billable hours, ancillary services and repairs of customer property primarily related to product sales in 2021.

Costs and expenses

Cost of product revenue for the year ended December 31, 2020 was $131.7 million, a decrease of $88.9 million, or 40%, from $220.6 million for the year ended December 31, 2019.

The decrease was largely attributable to the reduction in product sales and approximately $8.7 million in credits related to tariff refunds.

Cost of rental revenue for the year ended December 31, 2020 was $49.1 million, a decrease of $20.8 million, or 30%, from $69.8 million for the year ended December 31, 2019.

The decrease was primarily attributable to lower repair costs and lower branch expenses.

Cost of product revenue for the year ended December 31, 2021 was $189.1 million, an increase of $57.4 million, or 44%, from $131.7 million for the year ended December 31, 2020.

The increase was largely attributable to an increase in product sales and costs associated with materials, freight and overhead, including increased labor costs in 2021.

Additionally, cost of product revenue in 2020 included $8.7 million in non-recurring credits related to tariff refunds.

Cost of rental revenue for the year ended December 31, 2021 was $54.4 million, an increase of $5.3 million, or 11%, from $49.1 million for the year ended December 31, 2020.

The increase was primarily due to higher repair and reactivation costs offset by decreased scrap and rework expense, lower depreciation expenses on our rental fleet and other savings resulting from lower activity compared to 2020.

Rental cost of sales in 2020 also included approximately $1.0 million in credits related to tariff refunds.

These decreases were partially offset by an increase in depreciation expense on a larger rental fleet during 2020 and higher scrap and rework expenses.

Cost of field service and other revenue for the year ended December 31, 2020 was $56.1 million, a decrease of $47.0 million, or 46%, from $103.2 million for the year ended December 31, 2019.

The decrease was mainly related to lower payroll costs associated with fewer field and branch personnel, an increase in gains from sales of field service vehicles of $3.2 million, lower depreciation, fuel and repair expenses on a smaller fleet of vehicles and various other savings resulting from lower overall activity.

Selling, general and administrative expense for the year ended December 31, 2020 was $39.7 million, a decrease of $11.9 million, or 23%, from $51.7 million for the year ended December 31, 2019.

The decrease was primarily due to lower personnel costs, including annual incentive bonuses, related to headcount and salary reductions during 2020, a reduction in professional fees, travel and entertainment costs and other decreases associated with certain targeted cost savings measures.

These reductions were partially offset by increases in stock-based compensation expense and foreign currency losses.

Severance expense for the year ended December 31, 2020 of $1.9 million was related to severance benefits associated with headcount reductions in the second and third quarters of 2020 resulting from the economic downturn and decline in demand for our products and services.

Interest income, net.

Interest income, net was $0.7 million in 2020 compared to $0.9 million in 2019, a decrease of $0.2 million.

The decrease was primarily due to lower interest income on cash invested in interest-bearing accounts and money market funds as a result of lower interest rates in 2020, partially offset by $0.5 million of interest income in 2020 associated with the tariff refunds.

Cost of field service and other revenue for the year ended December 31, 2021 was $73.7 million, an increase of $17.5 million, or 31%, from $56.1 million for the year ended December 31, 2020.

The increase was mainly related to higher personnel costs associated with higher wages and an increase in the number of field and branch personnel as well as higher fuel and other remobilization expenses associated with increased field service activity levels compared to the prior year.

Additionally, gains from sales of field service vehicles decreased by $3.4 million from 2020 as we rationalized our fleet vehicles in line with the headcount reductions in the prior year.

Selling, general and administrative expense for the year ended December 31, 2021 was $46.0 million, an increase of $6.3 million, or 16%, from $39.7 million for the year ended December 31, 2020.

The increase was largely attributable to increased personnel costs primarily related to higher salaries and wages and associated payroll taxes, increased annual incentive bonuses based on current year performance and higher stock-based compensation expense.

Additional increases from 2020 related to higher professional fees, information technology expenses and travel and entertainment expenses.

These increases were partially offset by a reduction in foreign currency losses.

Severance expense for the year ended December 31, 2020 of $1.9 million was related to severance benefits associated with headcount reductions resulting from the economic downturn and decline in demand for our products and services.

Interest income (expense), net.

Interest expense, net was $0.8 million in 2021 compared to interest income, net of $0.7 million in 2020.

The decrease in interest income, net of $1.5 million was primarily due to lower interest income on cash invested resulting from significantly lower interest rates in 2021 as well as the prior year period including $0.5 million of interest income recognized on tariff refunds.

Other income (expense), net.

Other expense, net for the year ended December 31, 2020 consisted of non-cash adjustments for the revaluation of the liability related to the TRA.

Other income, net for the year ended December 31, 2019 of $4.3 million consisted of a $5.3 million non-cash gain on the revaluation of the liability related to the TRA, partially offset by $1.0 million in offering expenses associated with the secondary offering of our Class A common stock in March 2019 by certain selling stockholders.

Other income, net for the year ended December 31, 2021 of $0.5 million related to a $0.9 million non-cash gain associated with the revaluation of the liability related to the TRA and $0.4 million for professional fees and other expenses associated with the 2021 Secondary Offering.

Other expense, net for the year ended December 31, 2020 of $0.6 million represented non-cash adjustments for the revaluation of the liability related to the TRA.

Income tax expense.

Income tax expense for the year ended December 31, 2021 was $7.7 million (10.2% effective tax rate) compared to $11.0 million (15.6% effective tax rate) for 2020.

Income tax expense for the year ended December 31, 2020 included a $2.2 million benefit primarily comprised of tax credit adjustments and the revaluation of our deferred tax asset resulting from a change in our forecasted state tax rate.

Our effective tax rate is lower than the federal statutory rate of 21% primarily due to the fact that Cactus Inc.

Income tax expense for the year ended 2021 was primarily related to approximately $16.3 million expense associated with our 2021 operations and $1.3 million expense resulting from a change in our forecasted state tax rate.

This tax expense was partially offset by a $1.1 million benefit associated with permanent differences related to equity compensation and a $9.0 million tax benefit associated with the partial valuation allowance release in conjunction with 2021 redemptions of CW Units.

Partial valuation releases occur in conjunction with redemptions of CW Units as a portion of Cactus Inc.’s deferred tax assets from its investment in Cactus LLC becomes realizable.

Income tax expense for the year ended December 31, 2020 was primarily due to approximately $11.0 million expense associated with our 2020 operations and a $2.8 million expense associated with changes in our valuation allowance.

These expenses were partially offset by a $1.7 million tax benefit related to finalization of our 2019 tax returns and a $1.2 million benefit primarily comprised of tax credit adjustments and a change in our forecasted state tax rate.

Our effective tax rate is typically lower than the federal statutory rate of 21% due to the fact that Cactus Inc.

is only subject to federal and state income tax on its share of income from Cactus LLC.

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We expect that our existing cash on hand, cash generated from operations and available borrowings under our ABL Credit Facility will be sufficient for the next 12 months to meet working capital requirements, anticipated capital expenditures, expected TRA liability payments, anticipated tax liabilities and dividends to holders of our Class A common stock as well as pro rata cash distributions to holders of CW units (other than Cactus Inc.).

We currently estimate our net capital expenditures for the year ending December 31, 2021 will range from $10 million to $15 million, excluding acquisitions, mostly related to rental fleet investments.

We currently estimate our net capital expenditures for the year ending December 31, 2022 will range from $20 million to $30 million, excluding acquisitions, mostly related to rental fleet investments, including drilling tools, additional investment and expansion of our manufacturing facility in Bossier and the further development of a research and development facility.

We continuously evaluate our capital expenditures, and the amount we ultimately spend will depend on a number of factors, including, among other things, demand for rental assets, available capacity in existing locations, prevailing economic conditions, market conditions in the E&P industry, customers’ forecasts, volatility and company initiatives.

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Net cash provided by operating activities was $63.8 million and $143.4 million for the years ended December 31, 2021 and 2020, respectively.

Operating cash flows for 2020 decreased from 2019 primarily due to the overall reduction in revenue due to the economic downturn evidenced by a decrease in net income adjusted for certain noncash items offset by an increase in cash generated from changes in net working capital and $14.2 million in tariff refunds.

Operating cash flows for 2021 decreased from 2020 primarily due to an increase in working capital, largely related to the increase in accounts receivable and inventories, partially offset by an increase in accounts payable and other liabilities.

Additionally, 2020 included $14.2 million in tariff refunds.

A $4.5 million decrease in TRA payments offset these decreases slightly.

Net cash used in investing activities was $11.6 million and $18.1 million for the years ended December 31, 2021 and 2020, respectively.

The decrease was primarily due to lower capital expenditures associated with our rental fleet in 2020 due to reductions in purchases as a result of the current industry environment as well as an increase in proceeds from asset sales.

The decrease was primarily due to lower capital expenditures associated with our rental fleet in 2021 as well as lower proceeds from sale of assets.

Net cash used in financing activities was $39.4 million and $40.2 million for the years ended December 31, 2021 and 2020, respectively.

The increase was attributable to an increase of $12.9 million in dividend payments to holders of Class A

common stock and an increase of $7.9 million in Cactus LLC member distributions, partially offset by a $2.2 million reduction in payments on finance leases.

The decrease was primarily related to the $6.6 million decrease in Cactus LLC member distributions offset by a $4.0 million increase in dividend payments and a $1.8 million increase in share repurchases from employees to satisfy tax withholding obligations related to restricted stock units that vested during the period.

Critical Accounting Policies and Estimates

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Such estimates could be modified, as impairment could arise as a result of changes in supply and demand fundamentals, technological developments, new competitors with cost advantages and the cyclical nature of the oil and gas industry.

We evaluate long‑lived assets for potential impairment indicators whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.

We evaluate long‑lived assets for potential impairment indicators whenever events or changes in circumstances indicate that the carrying amount of an

asset may not be recoverable.

Long‑lived assets assessed for impairment are grouped at the lowest level for which identifiable cash flows are available, and a provision made where the cash flow is less than the carrying value of the asset.

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actually realizes or is deemed to realize in certain circumstances as a result of (i) certain increases in tax basis that occur as a result of Cactus Inc.’s acquisition (or deemed acquisition for U.S.

federal income tax purposes) of all or a portion of such TRA Holder’s CW Units in connection with our

IPO or any subsequent offering, or pursuant to any other exercise of the Redemption Right or the Call Right, (ii) certain increases in tax basis resulting from the repayment of borrowings outstanding under Cactus LLC’s term loan facility in connection with our IPO and (iii) imputed interest deemed to be paid by Cactus Inc.

federal income tax purposes) of all or a portion of such TRA Holder’s CW Units in connection with our IPO or any subsequent offering, or pursuant to any other exercise of the Redemption Right or the Call Right, (ii) certain increases in tax basis resulting from the repayment of borrowings outstanding under Cactus LLC’s term loan facility in connection with our IPO and (iii) imputed interest deemed to be paid by Cactus Inc.

as a result of, and additional tax basis arising from, any payments Cactus Inc.

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Recent Accounting Pronouncements

See Note 2 in the Notes to the Consolidated Financial Statements for discussion of recent accounting pronouncements.

There were no new accounting standards adopted in 2021 and there are no new accounting pronouncements issued but not yet effective that are expected to have a material impact on our consolidated financial statements.

While inflationary cost increases can affect our income from operations’ margin, we believe that inflation generally has not had, and in the near future is not expected to have, a material adverse effect on our results of operations.

Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy, and we tend to experience inflationary pressure on wages and raw materials.

Currently, the United States is experiencing the highest inflation in decades primarily due to supply-chain issues, a shortage of labor and a build-up of demand for goods and services.

The most noticeable adverse impact to our business has been increased costs associated with freight, materials, vehicle-related costs and personnel expenses.

While we believe that this current rate of inflation is transitory as it is pandemic-driven, we are unsure how long an elevated rate will continue.

Additionally, we cannot be confident that costs will return to the lower levels experienced in prior years.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis