ProPetro Holding Corp.: Form 10-Q for the period ended Mar 31, 2023

The financial information, discussion and analysis that follow should be read in conjunction with our consolidated financial statements and the related notes included in the Form 10-K as well as the financial and other information included therein.

Unless otherwise indicated, references in this "Management's Discussion and Analysis of Financial Condition and Results of Operations" to the "Company," "we," "our," "us" or like terms refer to ProPetro Holding Corp. and its subsidiaries.

Overview

We are a leading integrated oilfield services company, located in Midland, Texas, focused on providing innovative hydraulic fracturing, wireline and other complementary oilfield completion services to leading upstream oil and gas companies engaged in the exploration and production ("E&P") of North American oil and natural gas resources. Our operations are primarily focused in the Permian Basin, where we have cultivated longstanding customer relationships with some of the region's most active and well-capitalized E&P companies. The Permian Basin is widely regarded as one of the most prolific oil-producing areas in the United States, and we believe we are one of the leading providers of completion services in the region.

Our completion services segment includes hydraulic fracturing, wireline and cement operations. Our hydraulic fracturing operations account for the significant portion of our operations, and our hydraulic fracturing operations revenue is approximately 79.0% of our total revenues, while wireline and cement accounts for our remaining revenues. Our total available hydraulic horsepower ("HHP") in our hydraulic fracturing operations as of March 31, 2023, was 1,355,000 HHP, which was comprised of 340,000 HHP of our Tier IV Dynamic Gas Blending ("DGB") equipment and 1,015,000 HHP of conventional Tier II equipment. Our hydraulic fracturing fleets range from approximately 50,000 to 80,000 HHP depending on the job design and customer demand at the wellsite. Our equipment has been designed to handle the operating conditions commonly encountered in the Permian Basin and the region’s increasingly high-intensity well completions (including simultaneous hydraulic fracturing ("Simul-Frac"), which involves fracturing multiple wellbores at the same time), which are characterized by longer horizontal wellbores, more stages per lateral and increasing amounts of proppant per well. With the industry transition to lower emissions equipment and Simul-Frac, in addition to several other changes to our customers' job designs, we believe that our available capacity could decline if we decide to reconfigure our fleets to increase active HHP and backup HHP at wellsites. In addition, in September 2021, August 2022 and December 2022, we committed to additional conversions of our Tier II equipment to Tier IV DGB, and purchase of new Tier IV DGB equipment. As such, we entered into conversion and purchase arrangements with our equipment manufacturers for a total 362,500 HHP of Tier IV DGB equipment and as of March 31, 2023, we have received 250,000 HHP of the converted and new Tier IV DGB equipment and expect to receive the remaining 112,500 HHP by the second quarter of 2023. In August 2022 and December 2022, we entered into a three-year electric fleet leases for a total of four fleets with 60,000 HHP per fleet. We expect to take delivery of the electric fleets at different times during the second half of 2023. We currently have 23 wireline units and 26 cement units.

On December 31, 2018, we consummated the purchase of certain pressure pumping assets and real property from Pioneer Natural Resources USA, Inc. ("Pioneer") and Pioneer Pumping Services (the "Pioneer Pressure Pumping Acquisition") in exchange for 16.6 million shares of our common stock and $110.0 million in cash. In connection with the Pioneer Pressure Pumping Acquisition, we became a long-term service provider to Pioneer under a pressure pumping services agreement (the "Pioneer Services Agreement"), providing pressure pumping and related services to Pioneer for a term of up to ten years, with eight committed fleets; provided, Pioneer had the right to terminate the Pioneer Services Agreement, in whole or in part, effective as of December 31 of each of the calendar years of 2022, 2024 and 2026. Under the Pioneer Services Agreement, the Company was entitled to receive compensation if Pioneer were to idle committed fleets. The Pioneer Services Agreement was superseded by the agreement below.

On March 31, 2022, we entered into an amended and restated pressure pumping services agreement (the "A&R Pressure Pumping Services Agreement") in place of the Pioneer Services Agreement that was entered into in connection with the Pioneer Pressure Pumping Acquisition. The A&R Pressure Pumping Services Agreement, which was effective from January 1, 2022 to December 31, 2022, reduced the number of contracted fleets from eight fleets to six fleets, modified the pressure pumping scope of work and pricing mechanism for contracted fleets, and replaced the idle fees arrangement with equipment reservation fees (the "Reservation fees"). As part of the Reservation fees arrangement, the Company was entitled to receive compensation for all eligible contracted fleets that were made available to Pioneer at the beginning of every quarter in 2022 through the term of the A&R Pressure Pumping Services Agreement. This agreement expired at the conclusion of its term and was replaced by the Fleet One Agreement and Fleet Two Agreement described below.

On October 31, 2022, we entered into the Fleet One Agreement and the Fleet Two Agreement with Pioneer, pursuant to which we will provide hydraulic fracturing services with two committed fleets, subject to certain termination and release rights. The Fleet One Agreement was effective as of January 1, 2023 and will terminate on August 31, 2023. The Fleet Two Agreement was effective as of January 1, 2023 and was originally planned to terminate on the one year anniversary of the date on which the fleet dedicated thereunder converted from a Tier II diesel Simul-Frac fleet to a Tier IV dual fuel zipper fleet, which was expected to occur in May 2023. In February 2023, Pioneer provided the Company notice (i) stating that Pioneer intended to release the fleet under the Fleet Two Agreement effective upon the completion of operations on the pad where the performance of Services (as defined in the Fleet Two Agreement) is in progress on May 12, 2023 (the "Release Date") and (ii) requesting that the Company agree to the termination of the Fleet Two Agreement as of the Release Date. The Company agreed with such request, and, as a result, the Fleet Two Agreement was terminated as of the Release Date.

Effective September 1, 2022, we disposed of our coiled tubing assets to STEP Energy Services Ltd. ("STEP") and shut down our coiled tubing operations. We received cash of approximately $2.8 million and 2.6 million common shares of STEP valued at $11.9 million as consideration. Upon the sale of our coiled tubing assets, we recorded a loss on sale of $13.8 million.

On November 1, 2022, we consummated the acquisition of all of the outstanding limited liability company interests of Silvertip, which provides wireline perforation and ancillary services solely in the Permian Basin in exchange for 10.1 million shares of our common stock valued at $106.7 million, $30.0 million of cash, the payoff of $7.2 million of assumed debt, and the payment of certain other closing and transaction costs. At March 31, 2023, we had 23 wireline units available to provide wireline perforation and ancillary services. The Silvertip Acquisition positions the Company as a more resilient and diversified completions-focused oilfield services provider headquartered in the Permian Basin.

Our competitors include many large and small oilfield services companies, including Halliburton Company, Liberty Energy Inc., ProFrac Holding Corp., Nextier Oilfield Solutions Inc., Patterson-UTI Energy Inc., RPC, Inc., and a number of private and locally-oriented businesses. The markets in which we operate are highly competitive. To be successful, an oilfield services company must provide services that meet the specific needs of oil and natural gas E&P companies at competitive prices. Competitive factors impacting sales of our services are price, reputation, technical expertise, emissions profile, service and equipment design and quality, and health and safety standards. Although we believe our customers consider all of these factors, we believe price is a key factor in an E&P company's criteria in choosing a service provider. However, we have recently observed the energy industry and our customers shift to lower emissions equipment, which we believe will be an increasingly important factor in an E&P company's selection of a service provider. The transition to lower emissions equipment has been challenging for companies in the oilfield service industry because of the capital requirements. While we seek to price our services competitively, we believe many of our customers elect to work with us based on our operational efficiencies, productivity, equipment portfolio and quality, reliability, ability to manage multifaceted logistics challenges, commitment to safety and the ability of our people to handle the most complex Permian Basin well completions.

Our substantial market presence in the Permian Basin positions us well to capitalize on drilling and completion activity in the region. Primarily, our operational focus has been in the Permian Basin's Midland sub-basin, where our customers have operated. However, we have increased our operations in the Delaware sub-basin and are well-positioned to support further increases to our activity in this area in response to demand from our customers. Over time, we expect the Permian Basin's Midland and Delaware sub-basins to continue to command a disproportionate share of future North American E&P spending.

Through our Completion Services segment, which includes our hydraulic fracturing, cementing and wireline operations, we primarily provide hydraulic fracturing services to E&P companies in the Permian Basin. During the three months ended March 31, 2023, our hydraulic fracturing, cementing and wireline operations accounting for 79.0%, 6.3% and 14.7% of our total revenue, respectively. Our equipment has been designed to handle Permian Basin specific operating conditions and the region's increasingly high-intensity well completions, which are characterized by longer horizontal wellbores, more frac stages per lateral and increasing amounts of proppant per well. We plan to continually reinvest in our equipment to ensure optimal performance and reliability.

Our hydraulic fracturing, wireline and cementing operations have been aggregated into one reportable segment: "Completion Services." In connection with our divestiture of our coiled tubing operations and the Silvertip Acquisition, we have revised our reportable segment presentation from Pressure Pumping to Completion Services and have restated prior periods accordingly. Our now discontinued coiled tubing, drilling and flowback operations were aggregated into the "All Other" category.

Commodity Price and Other Economic Conditions

The oil and gas industry has traditionally been volatile and is characterized by a combination of long-term, short-term and cyclical trends, including domestic and international supply and demand for oil and gas, current and expected future prices for oil and gas and the perceived stability and sustainability of those prices, and capital investments of E&P companies toward their development and production of oil and gas reserves. The oil and gas industry is also impacted by general domestic and international economic conditions such as supply chain disruptions and inflation, political instability in oil producing countries, government regulations (both in the United States and internationally), levels of consumer demand, adverse weather conditions, and other factors that are beyond our control.

The geopolitical and macroeconomic consequences of the Russian invasion of Ukraine, including the associated sanctions, and the adverse impacts of the COVID-19 pandemic in recent years have resulted in volatility in supply and demand dynamics for crude oil and associated volatility in crude oil pricing. As the global response to the COVID-19 pandemic continues to wane, the demand and prices for crude oil have increased from the lows experienced in 2020, with the WTI average crude oil price reaching approximately $94 per barrel in 2022, the highest average price in the last nine years. We believe the improved crude oil pricing conditions have also been partly driven by declines in crude oil supplies, concerns over sanctions resulting from the Russia invasion of Ukraine and slower crude oil production growth due to the lack of reinvestment in the oil and gas industry in the last two years. However, in the wake of uncertainty in the banking sector following the failure of two regional U.S. banks and the growing risk of a global recession, which raised concerns over future crude oil demand destruction, and expanding commodity inventories, the WTI average crude oil price dropped to approximately $73 in March 2023, before rebounding to approximately $80 per barrel in April 2023 following the announcement by OPEC+ of further production cuts of approximately 1.16 million barrels per day.

With the significant increase in global crude oil prices from 2021, including the WTI crude oil price, there has been an increase in the Permian Basin rig count from approximately 179 at the beginning of 2021 to approximately 352 at the end of March 2023, according to Baker Hughes. Following the increase in rig count and the WTI crude oil price, the oilfield service industry has experienced increased demand for its completion services, and improved pricing. As a result of the growing demand for completion services and significant cost inflation across the industry, we negotiated pricing increases with certain of our customers for our completion services, depending on job design.

Although we have been operating in an improved pricing environment for completion services from 2022 onwards, the rapid increase in cost inflation and supply chain tightness could adversely impact our future profitability. The U.S. inflation rate has been steadily increasing since 2021. These inflationary pressures have resulted in and may result in additional increases to the costs of our oilfield goods, services and personnel, which in turn may cause our capital expenditures and operating costs to rise. Sustained levels of high inflation have likewise caused the U.S. Federal Reserve and other central banks to increase interest rates, and to the extent elevated inflation remains, we may experience further cost increases for our operations, including interest rates, labor costs and equipment. We cannot predict any future trends in the rate of inflation and a significant increase in or continued high levels of inflation, to the extent we are unable to timely pass-through the cost increases to our customers, would negatively impact our business, financial condition and results of operations.

Government regulations and investors are demanding the oil and gas industry transition to a lower emissions operating environment, including the upstream and oilfield service companies. As a result, we are working with our customers and equipment manufacturers to transition our equipment to a lower emissions profile. Currently, a number of lower emission solutions for pumping equipment, including Tier IV DGB, electric, direct drive gas turbine and other technologies have been developed, and we expect additional lower emission solutions will be developed in the future. We are continually evaluating these technologies and other investment and acquisition opportunities that would support our existing and new customer relationships. The transition to lower emissions equipment is quickly evolving and will be capital intensive. Over time, we may be required to convert substantially all of our conventional Tier II equipment to lower emissions equipment. We have transitioned our hydraulic fracturing equipment portfolio from approximately 10% lower emissions equipment in 2021 to approximately 35% in 2022, and expect to increase to approximately 65% by year end 2023. To the extent any of our customers have certain expectations or requirements with respect to emissions reductions from their contractors, if we are unable to continue quickly transitioning to lower emissions equipment, the demand for our services could be adversely impacted.

If the rig count and market conditions continue to improve, including improved customers' pricing and labor availability, and we are able to meet our customers' lower emissions equipment demands, we believe our operational and financial results will also continue to improve. If market conditions do not improve or decline in the future, and we are unable to increase our pricing or pass-through future cost increases to our customers, there could be a material adverse impact on our business, results of operations and cash flows.

Our results of operations have historically reflected seasonal tendencies, typically in the fourth quarter, relating to the holiday season, inclement winter weather and exhaustion of our customers' annual budgets. As a result, we typically experience declines in our operating and financial results in November and December, even in a stable commodity price and operations environment.

How We Evaluate Our Operations

Our management uses Adjusted EBITDA or Adjusted EBITDA margin to evaluate and analyze the performance of our various operating segments.

Adjusted EBITDA and Adjusted EBITDA Margin

We view Adjusted EBITDA and Adjusted EBITDA margin as important indicators of performance. We define EBITDA as our earnings, before (i) interest expense, (ii) income taxes and (iii) depreciation and amortization. We define Adjusted EBITDA as EBITDA, plus (i) loss/(gain) on disposal of assets, (ii) stock-based compensation, and (iii) other unusual or nonrecurring (income)/expenses, such as impairment charges, retention bonuses, severance, costs related to asset acquisitions, insurance recoveries, one-time professional fees and legal settlements. Adjusted EBITDA margin reflects our Adjusted EBITDA as a percentage of our revenues.

Adjusted EBITDA and Adjusted EBITDA margin are supplemental measures utilized by our management and other users of our financial statements such as investors, commercial banks, and research analysts, to assess our financial performance because it allows us and other users to compare our operating performance on a consistent basis across periods by removing the effects of our capital structure (such as varying levels of interest expense), asset base (such as depreciation and amortization), nonrecurring (income)/expenses and items outside the control of our management team (such as income taxes). Adjusted EBITDA and Adjusted EBITDA margin have limitations as analytical tools and should not be considered as an alternative to net income/(loss), operating income/(loss), cash flow from operating activities or any other measure of financial performance presented in accordance with GAAP.

Note Regarding Non-GAAP Financial Measures

Adjusted EBITDA and Adjusted EBITDA margin are not financial measures presented in accordance with GAAP ("non-GAAP"), except when specifically required to be disclosed by GAAP in the financial statements. We believe that the presentation of Adjusted EBITDA and Adjusted EBITDA margin provide useful information to investors in assessing our financial condition and results of operations because it allows them to compare our operating performance on a consistent basis across periods by removing the effects of our capital structure, asset base, nonrecurring expenses (income) and items outside the control of the Company. Net income (loss) is the GAAP measure most directly comparable to Adjusted EBITDA. Adjusted EBITDA and Adjusted EBITDA margin should not be considered as alternatives to the most directly comparable GAAP financial measure. Each of these non-GAAP financial measures has important limitations as analytical tools because they exclude some, but not all, items that affect the most directly comparable GAAP financial measures. You should not consider Adjusted EBITDA or Adjusted EBITDA margin in isolation or as a substitute for an analysis of our results as reported under GAAP. Because Adjusted EBITDA and Adjusted EBITDA margin may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

Reconciliation of net income (loss) to Adjusted EBITDA (in thousands):

(1) Other general and administrative expense, (net of reimbursement from insurance carriers) primarily relates to nonrecurring professional fees paid to external consultants in connection with our audit committee review, SEC investigation, shareholder litigation, legal settlement to a vendor and other legal matters, net of insurance recoveries. During the three months ended March 31, 2023 and 2022, we received reimbursement of approximately $0.3 million and $1.0 million, respectively, from our insurance carriers in connection with the SEC investigation and shareholder litigation.

(2) Includes $10.7 million of net tax refund (net of advisory fees) received in March 2022 from the Texas Comptroller of Public Accounts in connection with limited sales, excise and use tax of the period July 1, 2015 through December 31, 2018.

(3) Includes $3.8 million unrealized loss on short-term investment.

Results of Operations

In 2023, we conducted our business through three operating segments: hydraulic fracturing, cementing and wireline. For reporting purposes, the hydraulic fracturing, cementing and wireline operating segments are aggregated into our one reportable segment—Completion Services. We disposed of our coiled tubing assets and shut down our coiled tubing operations effective September 1, 2022. The results of our coiled tubing operations prior to September 1, 2022 are reflected in the "All Other" category.

The following table sets forth the results of operations for the periods presented:

(in thousands, except for percentages)

(1) Exclusive of depreciation and amortization.

(2) Inclusive of stock-based compensation.

(3) For definitions of the non-GAAP financial measures of Adjusted EBITDA and Adjusted EBITDA margin and reconciliation of Adjusted EBITDA to our most directly comparable financial measures calculated in accordance with GAAP, please read "How We Evaluate Our Operations". Included in our Adjusted EBITDA is reservation fees of $0 and $6.8 million for the three months ended March 31, 2023 and 2022, respectively.

(4) The non-GAAP financial measure of Adjusted EBITDA margin for the Completion Services segment is calculated by taking Adjusted EBITDA for the Completion Services segment as a percentage of our revenue for the Completion Services segment.

Three Months Ended March 31, 2023 Compared to the Three Months Ended March 31, 2022

Revenues. Revenues increased 49.8%, or $140.9 million, to $423.6 million during the three months ended March 31, 2023, as compared to $282.7 million during the three months ended March 31, 2022. Our Completion Services segment revenues increased 52.9%, or $146.5 million, for the three months ended March 31, 2023, as compared to the three months ended March 31, 2022. The increases were primarily attributable to the significant increase in our existing and new customers' activity levels, resulting in higher demand for completion services, improved pricing and the addition of wireline operations. The addition of wireline operations contributed $62.6 million of the increase in total revenues. As a result of our customers' increased activity levels, our effectively utilized fleet count rose to approximately 15.5 active fleets during the three months ended March 31, 2023, from approximately 13.7 active fleets for the three months ended March 31, 2022. Our revenue for the three months ended March 31, 2023 and 2022, included reservation fees charged to a customer of approximately $0 and $6.8 million, respectively.

Revenues from services other than Completion Services decreased 100.0%, or $5.6 million, to $0 for the three months ended March 31, 2023, as compared to $5.6 million for the three months ended March 31, 2022. The decrease in revenue from services other than Completion Services was due to the discontinuation of our coiled tubing operations effective September 1, 2022.

Cost of Services. Cost of services increased 42.2%, or $83.2 million, to $280.5 million for the three months ended March 31, 2023, as compared to $197.3 million during the three months ended March 31, 2022. Cost of services in our Completion Services segment increased $87.9 million for the three months ended March 31, 2023, as compared to the three months ended March 31, 2022. These increases were primarily attributable to the significantly increased activity levels resulting from the increased demand for our services, the addition of wireline operations and the impact of general cost inflation. The addition of wireline operations contributed to $41.0 million of the increase in total cost of services. As a percentage of Completion Services segment revenues (including reservation fees), Completion Services cost of services was 66.2% for the three months ended March 31, 2023, as compared to 69.5% for the three months ended March 31, 2022. Excluding reservation fees revenue of $0 and $6.8 million recorded during the three months ended March 31, 2023 and 2022, respectively, our Completion Services cost of services as a percentage of Completion Services revenues decreased to 66.2% during the three months ended March 31, 2023, as compared to 71.3% for the three months ended March 31, 2022. The decrease in the percentages was primarily a result of increased operational efficiencies and an increase in our active fleet count.

General and Administrative Expenses. General and administrative expenses decreased 9.3%, or $3.0 million, to $28.7 million for the three months ended March 31, 2023, as compared to $31.7 million for the three months ended March 31, 2022. The net decrease was primarily attributable to (i) a $7.8 million decrease in stock-based compensation expense driven by the acceleration of stock awards during the three months ended March 31, 2022 upon resignation of a former executive and (ii) a $1.4 million decrease in legal settlements, partially offset by (i) a $2.2 million increase in payroll expenses, (ii) a $0.9 million increase in acquisition related expenses, (iii) $3.1 million in other general and administrative expenses like travel, office expenses and insurance.

Excluding nonrecurring and non-cash items (stock-based compensation, insurance reimbursements, legal settlements, transaction expenses, retention bonuses and severance expenses), general and administrative expenses were $23.9 million during the three months ended March 31, 2023 compared to $18.8 million during the three months ended March 31, 2022.

Depreciation and Amortization. Depreciation and amortization increased 59.5%, or $18.9 million, to $50.8 million for the three months ended March 31, 2023, as compared to $31.9 million for the three months ended March 31, 2022. The increase was primarily attributable to (i) accelerated depreciation of power ends with premature failure of $12.5 million during the three months ended March 31, 2023, (ii) assets placed into service since March 31, 2022 and (iii) the addition of wireline assets which included $3.0 million of depreciation and $1.4 million of amortization of intangible assets.

Loss on Disposal of Assets. Loss on the disposal of assets increased 37.0%, or $6.0 million, to $22.1 million for the three months ended March 31, 2023, as compared to $16.1 million for the three months ended March 31, 2022. The increase was primarily attributable to the decommissioning of certain hydraulic fracturing equipment, replacement of certain major components in connection with our conversion of Tier II equipment to Tier IV DGB, higher intensity of use of our equipment, and the write-off of certain hydraulic fracturing equipment as a result of an accidental fire at a wellsite, partially offset by an increase in proceeds received from sale of assets during the three months ended March 31, 2023.

Interest Expense. Interest expense increased to $0.7 million for the three months ended March 31, 2023, as compared to $0.1 million for the three months ended March 31, 2022. We had $30.0 million in borrowings under our ABL Credit Facility for the three months ended March 31, 2023, compared to zero for the three months ended March 31, 2022.

Other (Income) Expense. Other expense was approximately $3.7 million for the three months ended March 31, 2023, as compared to other income of $10.4 million for the three months ended March 31, 2022. Other expense during the three months ended March 31, 2023 is primarily comprised of a $3.8 million unrealized loss on short-term investment. Other income during the three months ended March 31, 2022 was primarily comprised of a $10.7 million net tax refund of sales, excise and use taxes.

Income Taxes. Total income tax expense was $8.4 million resulting in an effective tax rate of 22.5% for the three months ended March 31, 2023, as compared to income tax expense of $4.1 million or an effective tax rate of 25.9% for the three months ended March 31, 2022. The change in income tax expense recorded during the three months ended March 31, 2023, compared to the three months ended March 31, 2022, is primarily attributable to the difference in the estimated pre-tax income for 2023, as compared to 2022.

Liquidity and Capital Resources

Our liquidity is currently provided by (i) existing cash balances, (ii) operating cash flows and (iii) borrowings under our ABL Credit Facility (as defined below). Our cash is primarily used to fund our operations, support growth opportunities and satisfy future debt payments. Our restricted cash, which was received from a customer, will be used solely for the construction or operation of certain electric hydraulic fracturing equipment. Our Borrowing Base (as defined below), as redetermined monthly, is tied to 85.0% to 90% of eligible accounts receivable. Changes to our operational activity levels and our customers' credit ratings have an impact on our total eligible accounts receivable, which could result in significant changes to our Borrowing Base and therefore, our availability under our ABL Credit Facility.

In addition, we received advance payments from a customer for our services, and the amount outstanding in connection with the advance payments as of March 31, 2023 was $22.0 million, which includes restricted cash of $18.3 million.

As of March 31, 2023, our borrowings under our ABL Credit Facility were $30.0 million and our total liquidity was approximately $149.2 million, consisting of cash, cash equivalents and restricted cash of $44.8 million and $104.4 million of availability under our ABL Credit Facility.

As of May 1, 2023, our borrowing under our ABL Credit Facility were $60.0 million and our total liquidity was approximately $166.1 million, consisting of cash, cash equivalents and restricted cash of $82.1 million and $84.0 million of availability under our ABL Credit Facility.

There can be no assurance that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Future cash flows are subject to a number of variables, and are highly dependent on the drilling, completion, and production activity by our customers, which in turn is highly dependent on oil and natural gas prices. Depending upon market conditions and other factors, we may issue equity and debt securities or take other actions necessary to fund our business or meet our future long-term liquidity requirements.

Capital Requirements, Future Sources and Use of Cash and Contractual Obligations

Capital expenditures incurred were $97.2 million during the three months ended March 31, 2023, as compared to $71.7 million during the three months ended March 31, 2022. The significant portion of our total capital expenditures incurred were maintenance capital expenditures and conversion of our hydraulic fracturing equipment to lower emissions equipment.

Our future material use of cash will be to fund our capital expenditures. Capital expenditures for 2023 are projected to be primarily related to capital expenditures to extend the useful life of our existing completion services assets, costs to convert some existing equipment to lower emissions equipment, strategic purchases and other ancillary equipment purchases, subject to market conditions and customer demand and potential strategic acquisitions. Our future capital expenditures depend on our projected operational activity, emission requirements and planned conversions to lower emissions equipment, among other factors, which could vary significantly throughout the year. We could incur significant additional capital expenditures if our projected activity levels increase during the course of the year, inflation and supply chain tightness continue to adversely impact our operations or we invest in new or different lower emissions equipment. The Company will continue to evaluate the emissions profile of its equipment over the coming years and may, depending on market conditions, convert or retire additional conventional Tier II equipment in favor of lower emissions equipment. The Company’s decisions regarding the retirement or conversion of equipment or the addition of lower emissions equipment will be subject to a number of factors, including (among other factors) the availability of equipment, including parts and major components, supply chain disruptions, prevailing and expected commodity prices, customer demand and requirements and the Company’s evaluation of projected returns on conversion or other capital expenditures. Depending on the impacts of these factors, the Company may decide to retain conventional equipment for a longer period of time or accelerate the retirement, replacement or conversion of that equipment.

We anticipate our capital expenditures will be funded by existing cash, cash flows from operations, and if needed, borrowings under our ABL Credit Facility. Our cash flows from operations will be generated from services we provide to our customers. In addition, our cash flows could be improved by prepayments received from certain customers in connection with our completion services contractual arrangements, as applicable.

We entered into contractual arrangements with our equipment manufacturers to purchase and convert Tier IV DGB equipment, with a total cost of approximately $41.9 million for the remainder of 2023. In 2022, we entered into a sand purchase agreement with a supplier with a take-or-pay commitment of $24.4 million for the remainder of 2023. We also entered into three-year equipment leases (the "Electric Fleet Lease") for a total of four electric hydraulic fracturing fleets with capacity of 60,000 HHP per fleet, which contains options to extend the lease or purchase the equipment at the end of the lease. The lease payments will commence when we take possession of the electric hydraulic fracturing pumps, which is expected to occur during the second half of 2023. The total estimated contractual commitment in connection with the Electric Fleet Lease is approximately $99.2 million, which excludes the cost associated with the option to purchase the equipment at the end of the lease. We also entered into a three year ("Power Equipment Lease") for certain power generation equipment. The lease payments are expected to commence when we take possession of the power generation equipment during the second half of 2023. The total estimated contractual commitment in connection with the Power Equipment Lease is approximately $59.6 million.

In the normal course of business, we enter into various contractual obligations and incur expenses in connection with routine growth, conversion and maintenance capital expenditures that impact our future liquidity. There were no other known future material contractual obligations as of March 31, 2023.

Cash, Restricted Cash and Cash Flows

The following table sets forth the historical cash flows for the three months ended March 31, 2023, and 2022:

(in thousands)

-30-

Cash Flows From Operating Activities

Net cash provided by operating activities was $73.1 million for the three months ended March 31, 2023, compared to $25.2 million for the three months ended March 31, 2022. The net increase of approximately $47.9 million was primarily due to the improvement in our net income, resulting from the significant increase in our existing and new customers' activity levels, resulting in higher demand for completion services, increased operational efficiencies and reduction in operational downtime. The increase in cash provided by operating activities was also impacted by timing of our receivable collections from our customers and payments to our vendors.

Cash Flows From Investing Activities

Net cash used in investing activities increased to $113.7 million for the three months ended March 31, 2023, from $64.0 million for the three months ended March 31, 2022. The increase was primarily attributable to maintenance capital expenditures and our investment in lower emissions Tier IV DGB equipment (conversion of Tier II equipment to Tier IV DGB equipment and new Tier IV DGB equipment).

Cash Flows From Financing Activities

Net cash used in financing activities increased to $3.4 million for the three months ended March 31, 2023, from $2.3 million for the three months ended March 31, 2022. The net increase in cash used in financing activities during the three months ended March 31, 2023, was primarily a result of an increase in the amount of net settlement of equity awards compared to the three months ended March 31, 2022.

Credit Facility and Other Financing Arrangements

Our revolving credit facility, as amended in 2018, had a total borrowing capacity of $300.0 million (subject to the borrowing base limit), with a maturity date of December 19, 2023. The revolving credit facility had a borrowing base of 85% of monthly eligible accounts receivable less customary reserves, as redetermined monthly. The revolving credit facility included a springing fixed charge coverage ratio to apply when excess availability was less than the greater of (i) 10% of the lesser of the facility size or the borrowing base or (ii) $22.5 million. Borrowings under the revolving credit facility accrued interest based on a three-tier pricing grid tied to availability, and we had the option to elect for loans to be based on either LIBOR or base rate, plus the applicable margin, which ranged from 1.75% to 2.25% for LIBOR loans and 0.75% to 1.25% for base rate loans, with a LIBOR floor of zero.

Effective April 13, 2022, the Company entered into an amendment and restatement of its revolving credit facility (as amended and restated, "ABL Credit Facility"). The ABL Credit Facility decreased the borrowing capacity to $150.0 million (subject to the Borrowing Base limit), with a maturity date extended to April 13, 2027. The ABL Credit Facility has a borrowing base of 85% to 90%, depending on the credit ratings of our accounts receivable counterparties, of monthly eligible accounts receivable less customary reserves (the "Borrowing Base"), as redetermined monthly. The Borrowing Base as of March 31, 2023, was approximately $140.3 million. The ABL Credit Facility includes a springing fixed charge coverage ratio to apply when excess availability is less than the greater of (i) 10% of the lesser of the facility size or the Borrowing Base or (ii) $10.0 million. Under this facility we are required to comply, subject to certain exceptions and materiality qualifiers, with certain customary affirmative and negative covenants, including, but not limited to, covenants pertaining to our ability to incur liens, indebtedness, changes in the nature of our business, mergers and other fundamental changes, disposal of assets, investments and restricted payments, amendments to our organizational documents or accounting policies, prepayments of certain debt, dividends, transactions with affiliates, and certain other activities. Borrowings under the ABL Credit Facility are secured by a first priority lien and security interest in substantially all assets of the Company.

Borrowings under the ABL Credit Facility accrue interest based on a three-tier pricing grid tied to availability, and we may elect for loans to be based on either the Secured Overnight Financing Rate ("SOFR") or the base rate, plus the applicable margin, which ranges from 1.50% to 2.00% for SOFR loans and 0.50% to 1.00% for base rate loans.

The loan origination costs relating to the ABL Credit Facility are classified as an asset in our balance sheet. As of March 31, 2023 and December 31, 2022, we had borrowings of $30.0 million outstanding under our ABL Credit Facility.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of March 31, 2023.

Critical Accounting Policies and Estimates

Other than the change in accounting estimate discussed in Note 1 of our Condensed Consolidated Financial Statements (Unaudited), there have been no material changes during the three months ended March 31, 2023 to the methodology applied by our management for critical accounting policies previously disclosed in our Form 10-K. Please refer to Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates" in our Form 10-K for a discussion of our critical accounting policies and estimates.

Recently Issued Accounting Standards

Disclosure concerning recently issued accounting standards is incorporated by reference to Note 2 of our Condensed Consolidated Financial Statements (Unaudited) contained in this Form 10-Q.

As of March 31, 2023, there have been no material changes in market risk from the information provided in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” or “Quantitative and Qualitative Disclosures of Market Risk” in our Form 10-K.

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to provide reasonable assurance that the information required to be disclosed by us in our reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to our management, including our 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, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this quarterly report. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of March 31, 2023.

Changes in Internal Control over Financial Reporting

There were no changes in our system of internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the quarter ended March 31, 2023 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Other than as set forth below, there have been no material changes to the risk factors disclosed in Part I, Item 1A. of our Form 10-K.

Adverse developments affecting the financial services industry, such as events or concerns involving liquidity, defaults or non-performance by financial institutions or transactional counterparties, could adversely affect the Company’s current and projected business operations and its financial condition and results of operations.

Events involving limited liquidity, defaults, non-performance or other adverse developments that affect financial institutions, transactional counterparties or other companies in the financial services industry or the financial services industry generally, concerns or rumors about such events or other similar risks, have in the past and may in the future lead to acute or market-wide liquidity problems. In addition, if any of the Company’s customers, suppliers or other business counterparties are unable to access funds held by such a financial institution, such parties’ ability to pay their obligations to the Company or to enter into new commercial arrangements requiring additional payments to the Company could be adversely affected.

Inflation and rapid increases in interest rates have led to a decline in the trading value of previously issued government securities with interest rates below current market interest rates. Although the U.S. Department of Treasury, Federal Deposit Insurance Corporation ("FDIC") and Federal Reserve Board have announced a program to mitigate the risk of potential losses on the sale of such instruments, widespread demands for customer withdrawals or other needs of financial institutions for immediate liquidity may exceed the capacity of such program. Additionally, the Company maintains cash balances at third-party financial institutions in excess of the FDIC standard insurance limits, and there is no guarantee that the U.S. Department of Treasury, FDIC and Federal Reserve Board will provide access to uninsured funds in the future in the event of the closure of such banks or financial institutions, or that they would do so in a timely fashion.

Access to funding sources and other credit arrangements in amounts adequate to finance the Company’s business operations could be significantly impaired by the foregoing factors that affect the Company, any financial institutions with which the Company enters into credit agreements or arrangements directly, or the financial services industry or economy in general. These factors could include, among others, events such as liquidity constraints or failures, the ability to perform obligations under various types of financial, credit or liquidity agreements or arrangements, disruptions or instability in the financial services industry or financial markets, or concerns or negative expectations about the prospects for companies in the financial services industry.

The results of events or concerns that involve one or more of these factors could include a variety of material and adverse impacts on the Company’s current and projected business operations and the Company’s financial condition and results of operations. These risks include, but may not be limited to, the following:

• delayed access to deposits or other financial assets or the uninsured loss of deposits or other financial assets;
• inability to enter into credit facilities or other working capital resources;
• potential or actual breach of contractual obligations that require the Company to maintain letters of credit or other credit support arrangements; or
• termination of cash management arrangements and/or delays in accessing or actual loss of funds subject to cash management arrangements.

In addition, investor concerns regarding the U.S. or international financial systems could result in less favorable commercial financing terms, including higher interest rates or costs and tighter financial and operating covenants, or systemic limitations on access to credit and liquidity sources, thereby making it more difficult for the Company to acquire financing on acceptable terms or at all. Any decline in available funding or access to cash and liquidity resources could, among other risks, adversely impact the Company’s ability to meet operating expenses or other obligations, financial or otherwise, result in breaches of the Company’s financial and/or contractual obligations, or result in violations of federal or state wage and hour laws. In addition, any further deterioration in the macroeconomic economy or financial services industry could lead to losses or defaults by the Company’s customers, vendors or suppliers. Any of these impacts, or any other impacts resulting from the factors described above or other related or similar factors, could have material adverse impacts on the Company’s liquidity and their current and/or projected business operations and financial condition and results of operations.