Item 7. Management’s Discussion and Analysis
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
You should read the following discussion and analysis of our financial condition and results of operations together with our audited consolidated financial statements and the related notes included in this Annual Report. Some of the information contained in this discussion and analysis or set forth elsewhere in this Annual Report, including information with respect to our plans and strategy for our business and related financing, includes forward‑looking statements that involve risks and uncertainties. You should read the " Risk Factors " section of this Annual Report for a discussion of important factors that could cause actual results to differ materially from the results described in or implied by the forward‑looking statements contained in the following discussion and analysis.
Basis of Presentation
This discussion of our results omits our results of operations and cash flows for the year ended December 31, 2021 and the comparison of our results of operations for the years ended December 31, 2022 and 2021, which may be found in our Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on February 23, 2023.
Unless otherwise indicated, references in this " Management’s Discussion and Analysis of Financial Condition and Results of Operations " to " ProPetro Holding Corp., " " the Company, " " we, " " our, " " us " or like terms refer to ProPetro Holding Corp. and its subsidiaries.
Overview
Our Business
We are a leading integrated oilfield service 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 includes our operating segments comprised of hydraulic fracturing, wireline and cementing operations. Our hydraulic fracturing operations account for approximately 78.5% of our total revenues and operations. Our total available hydraulic horsepower ("HHP") at December 31, 2023 w as 1,461,500 HHP, which was comprised of 452,500 HHP of our Tier IV Dynamic Gas Blending (“DGB”) dual-fuel equipment, 144,000 HHP of FORCE SM electric-powered equipment and 865,000 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 fleet capacity could decline if we decide to reconfigure our fleets to increase active HHP and backup HHP at wellsites. In addition, in 2021 and 2022, we committed to additional conversions of our Tier II equipment to Tier IV DGB, and to purchase new Tier IV DGB dual-fuel equipment. As such, we entered into conversion and purchase agreements with our equipment manufacturers for a total of 452,500 HHP of Tier IV DGB dual-fuel equipment and as of December 31, 2023, we have received all of the converted and new Tier IV DGB dual-fuel equipment. In 2022, we entered into three-year electric fleet leases for a total of four FORCE SM electric-powered hydraulic fracturing fleets with 60,000 HHP per fleet. As of December 31, 2023, we have recei ved 144,000 HHP of FOR CE SM electric-powered equipment. We currently expect to receive the remaining equipment associated with the second and third fleets and all equipment associated with the fourth fleet in the first half of 2024.
On November 1, 2022, we consummated the acquisition of all of the outstanding limited liability company interests of Silvertip Completion Services Operating, LLC (the “Silvertip Acquisition”), 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 December 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 service provider headquartered in the Permian Basin.
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On December 1, 2023, we consummated the purchase of the assets and operations of Par Five Energy Services LLC (“Par Five”), which provides cementing services in the Delaware Basin, in exchange for $25.4 million of cash . Par Five’s business complements our existing cementing business and enables us to serve both the Midland and Delaware Basins of the Permian Basin.
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.
We have historically conducted our business through four operating segments: hydraulic fracturing, wireline, cementing and coiled tubing. Prior to the fourth quarter of fiscal year 2023, our operating segments met the aggregation criteria and were aggregated into the “Completion Services” reportable segment and our coiled tubing operations (which were divested in September 2022) were shown in the “All Other” category. Effective as of the fourth quarter of fiscal year 2023, we revised our segment reporting as we determined that our three operating segments no longer met the criteria to be aggregated. Our Hydraulic Fracturing and Wireline operating segments meet the criteria of a reportable segment. Our cementing and our divested coiled tubing segments are not material, are not separately reportable, and are included within the “All Other” category. Prior period segment information has been revised to conform to our current presentation. For additional financial information on our reportable segments presentation, please see reportable segment information in Part II - Item 8, "Financial Statements and Supplementary Data."
Pioneer Pressure Pumping Acquisition
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, LLC in the Pioneer Pressure Pumping Acquisition in exchange for 16.6 million shares of our common stock and $110.0 million in cash, and concurrently entered into a pressure pumping services agreement (the "Pioneer Services Agreement") with Pioneer.
On March 31, 2022, we entered into an amended and restated pressure pumping services agreement (the “A&R Pressure Pumping Services Agreement”) to replace the Pioneer Services Agreement that was entered into in connection with the Pioneer Pressure Pumping Acquisition. 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 two pressure pumping services agreements (the “Fleet One Agreement” and the “Fleet Two Agreement”) with Pioneer, pursuant to which we provided 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 was terminated on August 31, 2023. The Fleet Two Agreement was effective as of January 1, 2023 and was terminated on May 12, 2023. In October 2023, Pioneer entered into a merger agreement with Exxon Mobil Corporation.
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, war and 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.
Since October 2023, an ongoing conflict between Israel and Palestinian militants in the Israel-Gaza region has led to significant armed hostilities. The geopolitical and macroeconomic consequences of this conflict remain uncertain, and such events, or any further hostilities in the Israel-Gaza region or elsewhere, could severely impact the world economy, the demand for and price of crude oil and the oil and gas industry generally and may adversely affect our financial condition.
Similarly, 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 began to wane, the demand and prices for crude oil increased from the lows experienced in 2020, with the WTI average crude oil price
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reaching approximately $94 per barrel in 2022, the highest average price in the prior nine years. However, in 2023, the WTI average crude oil price declined to approximately $78 per barrel. We believe that the volatility of crude oil prices in recent years has been partly driven by declines in crude oil supplies, concerns over sanctions resulting from Russia's invasion of Ukraine, concerns over a potential disruption of Middle Eastern oil supplies resulting from the ongoing conflict between Israel and Palestinian militants in the Israel-Gaza region, slower crude oil production growth due to the lack of reinvestment in the oil and gas industry in the last two years, recent OPEC+ production cuts of approximately 1.3 million barrels per day and concerns of a potential global recession resulting from high inflation and interest rates.
With the significant increase in global crude oil prices from 2021, including the WTI crude oil price, there was a significant increase in the Permian Basin rig count from approximately 179 at the beginning of 2021 to approximately 353 at the end of 2022, according to the Baker Hughes Company (“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. However, we have recently experienced a 13% decrease in the rig count in 2023 to 309 at the end of 2023 which resulted in a reduction in the demand for completion services and pressure on pricing of our services.
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 crude oil prices. 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, or further declines in crude oil prices would negatively impact our business, financial condition and results of operations. See Part II, Item 1A. "Risk Factors—We may be adversely affected by the effects of inflation."
Government regulations and investors are demanding the oil and gas industry transition to a lower emissions operating environment, including 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 dual-fuel , FORCESM 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 available equipment portfolio from approximately 10% lower emissions equipment in 2021 to approximately 35% in 2022 and 60% in 2023, and expect to increase to approximately 65% by the end of the first half of 2024. 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 Permian Basin rig count and market conditions improve, including improved pricing for our services 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 the rig count or 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.
2023 Operational Highlights
Over the course of the year ended December 31, 2023:
• improved pricing and increased operational efficiency at wellsites ;
• our average effectively utilized hydraulic fracturing fleet count was approximately 15 active fleets, consistent with 15 active fleets in 2022;
• successfully integrated our wireline business with our existing hydraulic fracturing and cementing businesses;
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• deployed two FORCE SM electric-powered hydraulic fracturing fleets with a total capacity of 120,000 HHP, and transitioned 452,500 HHP of our equipment portfolio to lower emissions, Tier IV DGB dual-fuel equipment. By adding two additional electric fleets by the end of the first half of 2024, our available equipment portfolio is expected to be comprised of approximately 65% lower emissions (FORCE SM electric and Tier IV DGB dual-fuel), and 35% conventional diesel equipment;
• published our inaugural sustainability report, which describes our commitment to building a sustainable business that supports the safe, reliable production of the energy the world needs by offering competitive, value-driving services to customers, while benefitting our shareholders, communities, and other stakeholders; and
• on December 1, 2023, we consummated the purchase of the assets and operations of Par Five, which provides cementing services in the Delaware Basin.
2023 Financial Highlights
Financial highlights for the year ended December 31, 2023:
• revenue increased $350.7 million, or 27.4%, to $1,630.4 million, as compared to $1,279.7 million for the year ended December 31, 2022;
• cost of services (exclusive of depreciation and amortization) increased $249.0 million or 28.2% to $1,131.8 million, as compared to $882.8 million for the year ended December 31, 2022; cost of services as a percentage of revenue increased to 69.4% in 2023 compared to 69.0% for the year ended December 31, 2022;
• general and administrative expenses, inclusive of stock-based compensation, increased $2.6 million, or 2.3% to $114.4 million, as compared to $111.8 million for the year ended December 31, 2022;
• no impairment expense was recorded during the year December 31, 2023, compared to $57.5 million impairment expense recorded during the year ended December 31, 2022 related to our DuraStim® electric-powered hydraulic fracturing equipment;
• net income was $85.6 million, compared to $2.0 million for the year ended December 31, 2022. Diluted net income per common share was $0.76, compared to $0.02 for the year ended December 31, 2022. Adjusted EBITDA of approximately $404.0 million increased 27.6%, compared to $316.6 million for the year ended December 31, 2022 (see reconciliation of Adjusted EBITDA to net income in the subsequent section "How We Evaluate Our Operations");
• our total liquidity was $134.4 million , consisting of cash, cash equivalents and restricted cash of $33.4 million and remaining availability of $101.0 million under our ABL Credit Facility; $45.0 million of borrowings as of December 31, 2023 under our ABL Credit Facility; and
• the Company repurchased and retired 5.8 million shares of common stock for an aggregate of $51.7 million, an average price per share of $8.93 including commissions, under the repurchase program. As of December 31, 2023, $48.3 million remained authorized for future repurchases of common stock under the repurchase program.
• In connection with the review of our power ends estimated useful life, effective January 1, 2023, we are writing off the remaining book value of power ends that prematurely fail as accelerated depreciation. These write-off amounts were $12.5 million, $11.8 million, $8.4 million and $6.0 million for the three months ended March, 31, 2023, June 30, 2023, September 30, 2023 and December 31, 2023, respectively. However, to conform to prior year presentation, we have presented these write-off amounts within loss on disposal of assets for the year ended December 31, 2023. In 2022 and 2021, we wrote off the remaining book value of prematurely failed and disposed of power ends to loss on disposal of assets.
Our Assets and Operations
Completion services includes our hydraulic fracturing, wireline and cementing operations. We primarily provide these services to E&P comp anies in the Permian Basin. During the year ended December 31, 2023, our hydraulic fracturing, wireline and cementing operations accounted for 78.5%, 14.1% and 7.4% 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.
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How We Generate Revenue
We generate revenue through our completion services, and more specifically, by providing hydraulic fracturing services to our customers. We own and operate a fleet of mobile hydraulic fracturing, wireline and cementing units and other auxiliary equipment to perform completion services to E&P companies. We also provide personnel and services that are tailored to meet each of our customers’ needs.
Hydraulic fracturing operations account for a significant portion of our total revenue. We charge our customers on a per‑job basis, in which we set pricing terms after receiving full specifications for the requested job, including the lateral length of the customer’s wellbore, the number of frac stages per well, the amount of proppant and chemicals to be used and other parameters of the job.
In addition to hydraulic fracturing services, we generate revenue through other completion services that we provide to our customers, including cementing, wireline and other related services. These completion services are complementary to each other and are undertaken in unison with hydraulic fracturing services. They are provided through various contractual arrangements, including on a turnkey contract basis, in which we set a price to perform a particular job, or a daywork contract basis, in which we are paid a set price per day for our services. We are also sometimes paid by the hour for these complementary services.
Demand for our services is largely dependent on oil and natural gas prices, and our customers’ well completion budgets and rig count. Our revenue, profitability and cash flows are highly dependent upon prevailing crude oil prices and expectations about future prices. For many years, oil prices and markets have been extremely volatile. Prices are affected by many factors beyond our control. The average WTI oil price per barrel was approximately $78 , $94 and $68 for the years ended December 31, 2023, 2022 and 2021, respectively. In January 2024, the WTI oil price was approximately $74 p er barrel. If the WTI oil price declines in the future or remains highly volatile, demand for our services may be negat ively impacted, which could result in a significant decrease in our future profitability and cash flows. We monitor oil and natural gas prices and the Permian Basin rig count to enable us to more effectively plan our business and forecast the demand for our services.
The historical weekly average Permian Basin rig count based on Baker Hughes rig count information was as follows:
Year Ended December 31,
Drilling Rig Type (Permian Basin) 2023 2022 2021
Directional 3 3 2
Horizontal 323 318 227
Vertical 9 14 11
Total 335 335 240
Average Permian Basin rig count to U.S. rig count 48.7 % 46.3 % 50.5 %
Costs of Conducting our Business
The principal direct costs involved in operating our business are direct labor, expendables and other direct costs.
Direct Labor Costs. Payroll and benefit expenses related to our crews and other employees that are directly or indirectly attributable to the effective delivery of services are included in our operating costs. Direct lab or costs amounted to 28.7% and 27.7% of total costs of service for the years ended December 31, 2023 and 2022, respectively. The increase in our direct labor costs percentage is driven by wage adjustments and higher headcount resulting from business acquisitions.
Expendables. Expendables include the product and freight costs associated with proppant, chemicals and other consumables used in our completion services and other operations. These costs comprise a substantial variable component of our service costs, particularly with respect to the quantity and quality of sand and chemicals demanded when providing hydraulic fracturing services. Expendable product costs comprised approximately 32.9% and 33.6% of total costs of service for the years ended December 31, 2023 and 2022, respectively. The percentage decrease in our expendables in 2023 was primarily attributable to certain customers electing to directly source sand and the associated logistics.
Other Direct Costs. We incur other direct expenses related to our service offerings, including the costs of fuel, repairs and maintenance, general supplies, equipment rental and other miscellaneous operating expenses. Fuel is consumed both in the operation and movement of our equipment. Repairs and maintenance costs are expenses directly related to upkeep of equipment, which have been amplified by the demand for higher horsepower jobs. Capital expenditures to upgrade or extend the useful life of equipment are capitalized and are not included in other direct costs. Other direct costs were 38.4% and 38.7% of total costs of service for the years ended December 31, 2023 and 2022, respectively.
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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, (iii) other expense/(income) and (iv) 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 and 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.
The following tables provide a reconciliation of Adjusted EBITDA to the GAAP financial measure of net income (loss) for each of our reportable segments for the specified periods (in thousands):
Hydraulic Fracturing
Wireline All Other
Year ended December 31, 2023
Net income $ 131,343 $ 42,051 $ 17,882
Depreciation and amortization 156,057 18,762 5,845
Interest expense
1,014 — 14
Loss on disposal of assets 71,756 562 796
Other expense (1)
6,000 — —
Other general and administrative expense
4 — 28
Retention bonus and severance expense 635 555 100
Adjusted EBITDA
$ 366,809 $ 61,930 $ 24,665
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Hydraulic Fracturing Wireline All Other
Year ended December 31, 2022
Net income (loss) $ 71,697 $ 5,388 $ (7,865)
Depreciation and amortization
117,753 2,619 7,329
Impairment expense (2)
57,454 — —
Loss (gain) on disposal of assets 88,765 (77) 13,953
Other income (3)
(2,668) (4) —
Other general and administrative expense (4)
5,124 — —
Severance expense 1,061 — 17
Adjusted EBITDA
$ 339,186 $ 7,926 $ 13,434
Hydraulic Fracturing Wireline All Other
Year ended December 31, 2021
Net loss $ (15,292) $ — $ (427)
Depreciation and amortization
124,999 — 8,076
Loss on disposal of assets
64,986 — 14
Severance expense — — 30
Adjusted EBITDA
$ 174,693 $ — $ 7,693
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(1) Includes settlement expenses resulting from routine audits.
(2) Represents expense in connection with the impairment of our DuraStim® electric-powered hydraulic fracturing equipment.
(3) Includes $2.7 million of non-cash income from fixed asset inventory received as part of a settlement of warranty claims with an equipment manufacturer.
(4) Includes legal settlement to a vendor and other legal matters, net of reimbursement from insurance carriers.
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Results of Operations
In 2023, we conducted our business through three operating segments: hydraulic fracturing, wireline, and cementing. Our cementing operating segment and coiled tubing operations are shown in the “All Other” category for segment reporting purposes. We disposed of our coiled tubing assets and shut down our coiled tubing operations effective September 1, 2022 .
Year Ended December 31, 2023 Compared to Year Ended December 31, 2022
(in thousands, except percentages)
Year Ended December 31, Change
2023 2022 Variance %
Revenue
Hydraulic Fracturing $ 1,280,523 $ 1,143,216 $ 137,307 12.0 %
Wireline 229,599 31,188 198,411 636.2 %
All Other (1)
120,277 105,297 14,980 14.2 %
Total revenue 1,630,399 1,279,701 350,698 27.4 %
Cost of services (2)
Hydraulic Fracturing 886,157 776,021 110,136 14.2 %
Wireline 155,357 21,141 134,216 634.9 %
All Other (1)
90,287 85,658 4,629 5.4 %
Total cost of services 1,131,801 882,820 248,981 28.2 %
General and administrative expense (3)
114,354 111,760 2,594 2.3 %
Depreciation and amortization 180,886 128,108 52,778 41.2 %
Impairment expense — 57,454 (57,454) (100.0) %
Loss on disposal of assets 73,015 102,150 (29,135) (28.5) %
Interest expense 5,308 1,605 3,703 230.7 %
Other expense (income) 9,533 (11,582) 21,115 182.3 %
Income tax expense 29,868 5,356 24,512 457.7 %
Net income $ 85,634 $ 2,030 $ 83,604 4,118.4 %
Adjusted EBITDA (4)
$ 403,960 $ 316,590 $ 87,370 27.6 %
Adjusted EBITDA Margin (4)
24.8 % 24.7 % 0.1 % 0.4 %
Hydraulic Fracturing segment results of operations:
Revenue $ 1,280,523 $ 1,143,216 $ 137,307 12.0 %
Cost of services $ 886,157 $ 776,021 $ 110,136 14.2 %
Adjusted EBITDA $ 366,809 $ 339,186 $ 27,623 8.1 %
Adjusted EBITDA Margin (5)
28.6 % 29.7 % (1.1) % (3.7) %
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(1) Includes our cementing and our disposed of coiled tubing operations.
(2) Exclusive of depreciation and amortization.
(3) Inclusive of stock‑based compensation.
(4) For definitions of the non‑GAAP financial measures of Adjusted EBITDA and Adjusted EBITDA margin and reconciliation of Adjusted EBITDA and Adjusted EBITDA margin 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 and idle fees of $0 and $27.0 million for the years ended December 31, 2023 and 2022, respectively.
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(5) The non‑GAAP financial measure of Adjusted EBITDA margin for the Hydraulic Fracturing segment is calculated by taking Adjusted EBITDA for the Hydraulic Fracturing segment as a percentage of our revenues for the Hydraulic Fracturing segment.
Revenue. Revenue increased 27.4%, or $350.7 million, to $1,630.4 million for the year ended December 31, 2023, as compared to $1,279.7 million for the year ended December 31, 2022. Revenue by reportable segment was as follows:
Hydraulic Fracturing. Our hydraulic fracturing segment revenues increased 12.0%, or $137.3 million for the year ended December 31, 2023, as compared to the year ended December 31, 2022. The increase was primarily attributable to the increase in our existing and new customers' activity levels, resulting in higher demand for completion services, and improved pricing. Our effectively utilized hydraulic fracturing fleet count was flat at 15 active fleets for the year ended December 31, 2023, as in the year ended December 31, 2022. The effectively utilized fleet count is determined by dividing the total number of days our fleets were actively working at wellsites during the month by 25 days (predetermined number of expected active work days in the month). Our revenue for the years ended December 31, 2023 and December 31, 2022 included reservation fees charged to a customer of approximately $0 and $27.0 million, respectively.
Wireline. Our wireline segment revenue increased 636.2%, or $198.4 million for the year ended December 31, 2023, as compared to the year ended December 31, 2022. The increase was primarily attributable to a full year of activity for the year ended December 31, 2023 compared to only 61 days of activity during year ended December 31, 2022 since the wireline business was acquired on November 1, 2022.
All Other. Revenue from the All Other category comprising of our cementing and our disposed of coiled tubing operations increased 14.2%, or $15.0 million for the year ended December 31, 2023, as compared to the year ended December 31, 2022. The increase was primarily attributable to the increase in our existing and new customers' activity levels, resulting in higher demand for completion services, and improved pricing, partially offset by the discontinuation of our coiled tubing operations effective September 1, 2022.
Cost of Services. Cost of services increased 28.2%, or $249.0 million, to $1,131.8 million for the year ended December 31, 2023, from $882.8 million during the year ended December 31, 2022. Cost of services by reportable segment was as follows:
Hydraulic Fracturing. C ost of services for our hydraulic fracturing segment increased $110.1 million during the year ended December 31, 2023, as compared to the year ended December 31, 2022. The increase was primarily attributable to increased activity levels resulting from the increased demand for our services as compared to 2022, and the impact of general cost inflation. As a percentage of hydraulic fracturing revenues (including reservation fees), hydraulic fracturing cost of services increased to 69.2% for the year ended December 31, 2023, as compared to 67.9% for the year ended December 31, 2022. Excluding reservation fees revenue of $0 and $27.0 million for the years ended December 31, 2023 and 2022, respectively, our hydraulic fracturing cost of services as a percentage of hydraulic fracturing revenues for the years ended December 31, 2023 and 2022 was approximately 69.2% and 69.5%, respectively. The decrease was a result of increased operational efficiencies and improved customer pricing, partially offset by costs of $38.0 million associated with the replacement of fluid ends during the year ended December 31, 2023 . Fluid ends were capitalized and depreciated in 2022. Effective January 1, 2023, the Company commenced expensing fluid ends as part of cost of services rather than capitalizing fluid ends as part of property and equipment as a result of the change in estimated useful life.
Wireline. Our wireline segment cost of services increased 634.9%, or $134.2 million for the year ended December 31, 2023, as compared to the year ended December 31, 2022. The increase was primarily attributable to a full year of activity for the the year ended December 31, 2023 compared to only 61 days of activity during year ended December 31, 2022 since the wireline business was acquired on November 1, 2022.
All Other. Cost of services for the All Other category comprising of our cementing and our disposed of coiled tubing operations increased 5.4%, or $4.6 million for the year ended December 31, 2023, as compared to the year ended December 31, 2022. The increase was primarily attributable to increased activity levels resulting from the increased demand for our services as compared to 2022, and the impact of general cost inflation, partially offset by the discontinuation of our coiled tubing operations effective September 1, 2022.
General and Administrative Expenses. General and administrative expen ses increased 2.3%, or $2.6 million, to $114.4 million for the y ear ended December 31, 2023, as compared to $111.8 million for the year ended December 31, 2022. The net increase was primarily attributable to (i) a $6.3 million increase in payroll and related expenses, (ii) a $5.1 million increase in utilities, advertising and other office expenses, (iii) a $2.1 million increase in travel expenses, and (iv) a $0.4 million net increase in
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other general and administrative expenses, partially offset by (i) a $7.4 million decrease in stock-based compensation expense primarily attributable to non-recurring incremental stock-based compensation in 2022 resulting from the acceleration of stock awards in connection with the resignation of former executives and (ii) a $3.9 million decrease in one-time legal settlement expenses.
Excluding nonrecurring and non-cash items ( i.e., stock-based compensation of $14.5 million, legal settlements (net of insurance reimbursements) of $0.7 million, transaction expenses of $2.3 million, and retention bonuses and severance expenses of $2.3 million), general and administrative expenses were $94.6 million for the year ended December 31, 2023, as compared to $80.3 million for the year ended December 31, 2022.
Depreciation and Amortization. Depreciation and amortization increased 41.2%, or $52.8 million, to $180.9 million for the yea r ended December 31, 2023, as compared to $128.1 million for the year ended December 31, 2022. The increase was primarily attributable to the increase in our fixed asset base as of December 31, 2023.
Impairment Expense. There was no impairment expense during the year ended December 31, 2023. During the year ended December 31, 2022, we recorded $57.5 million in connection with the impairment of our DuraStim® electric powered hydraulic fracturing equipment, which is included in our Hydraulic Fracturing reportable segment.
Loss on Disposal of Assets. Loss on the disposal of assets decreased 28.5%, or $29.1 million, to $73.0 million for the year ended December 31, 2023, as compared to $102.1 million for the year ended December 31, 2022. The decrease was primarily attributable to a loss of approximately $13.8 million from the disposal of our coiled tubing assets on September 1, 2022 and the Company expensing costs associated with replacement of fluid ends as part of cost of services resulting from the change in estimated useful life effective January 1, 2023, partially offset by losses incurred from the decommissioning/conversion of certain hydraulic fracturing equipment and the write-off of certain hydraulic fracturing equipment as a result of an accidental fire at a wellsite in March 2023.
Interest Expense. Interest expense increased to $5.3 million for the yea r ended December 31, 2023, as compared to $1.6 million for t he year ended December 31, 2022. The increase was primarily attributable to higher average outstanding borrowings under our ABL Credit Facility during the year ended December 31, 2023 and the addition of a finance lease for certain power generation equipment in August 2023.
Other Expense (Income). Other expense was approximately $9.5 million for the year ended December 31, 2023, as compared to other income of $11.6 million for the year ended December 31, 2022. Other expense during the year ended December 31, 2023 is primarily comprised of settlement expenses resulting from routine audits and one-time health insurance costs totaling approximately $7.4 million, and a $2.5 million unrealized loss on short-term investment. Other income during the year ended December 31, 2022 is comprised of a $10.7 million net tax refund of sales, excise and use taxes and $2.7 million of non-cash income from equipment parts inventory received from an equipment manufacturer as settlement of our warranty claims, partially offset by a $1.6 million unrealized loss on short-term investment.
Income Taxes. Total income tax expense was $29.9 million resulting in an effective tax rate of 25.9% for the year ended December 31, 2023, as compared to $5.4 million or an effective tax rate of 72.5% for the year ended December 31, 2022. The change in income tax expense recorded during the year ended December 31, 2023, compared to the year ended December 31, 2022, is primarily attributable to the difference in the impact of nondeductible expenses on the pre-tax income for 2023, as compared to 2022.
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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, fund share repurchases under our share repurchase program and satisfy future debt payments. Our restricted cash, which was received from a customer will be used solely for the construction or operation of FORCE SM electric-powered hydraulic fracturing equipment. Our Borrowing Base (as defined below), as redetermined monthly, is tied to the sum of 85% to 90% of monthly eligible accounts receivable and 80% of eligible unbilled accounts (up to a maximum of 25% of the Borrowing Base), in each case, depending on the credit ratings of our accounts receivable counterparties, less customary reserves. 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.
We received advance payments from a customer for our services, and the amount outstanding in connection with the advance payments was $19.2 million and $10.0 million as of December 31, 2023 an d 2022, respectively. These amounts included restricted cash of $0 and $10.0 million as of December 31, 2023 an d 2022, respectively.
As of December 31, 2023, our borrowings under our ABL Credit Facility were $45.0 million and our total liquidity was $134.4 million, consisting of cash and cash equivalents of $33.4 million and $101.0 million of availability under our ABL Credit Facility.
On May 17, 2023, the Board authorized and the Company announced a share repurchase program that allows the Company to repurchase up to $100 million of the Company's common stock beginning immediately and continuing through and including May 31, 2024. The shares may be repurchased from time to time in open market transactions, block trades, accelerated share repurchases, privately negotiated transactions, derivative transactions or otherwise, certain of which may be made pursuant to a trading plan meeting the requirements of Rule 10b5-1 under the Exchange Act, as amended, in compliance with applicable state and federal securities laws. The timing, as well as the number and value of shares repurchased under the program, will be determined by the Company at its discretion and will depend on a variety of factors, including management's assessment of the intrinsic value of the Company's common stock, the market price of the Company's common stock, general market and economic conditions, available liquidity, compliance with the Company's debt and other agreements, applicable legal requirements, and other considerations. The Company is not obligated to purchase any shares under the repurchase program, and the program may be suspended, modified, or discontinued at any time without prior notice. The Company expects to fund the repurchases using cash on hand and expected free cash flow to be generated through May 2024. During the year ended December 31, 2023 , the Company repurchased and retired 5.8 million shares of common stock for an aggregate of $51.7 million, an average price per share of $8.93 including commissions, under the repurchase program. As of December 31, 2023 , $48.3 million remained authorized for future repurchases of common stock under the repurchase program.
As part of our real estate consolidation strategy, we sold our corporate office building and the associated real property in August 2023 for cash proceeds of $4.7 million after commission and closing costs and recognized a gain on disposal of assets of $0.1 million during the year ended December 31, 2023 . We have subsequently relocated our corporate office to a leased office space. See "Note 17 - Leases" for further information.
On December 1, 2023, the Company consummated the purchase of the assets and operations of Par Five, which provides cementing services in the Delaware Basin in exchange for cash consideration of $25.4 million. Par Five’s business complements our existing cementing business and enables us to serve both the Midland and Delaware Basins of the Permian Basin.
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 and to continue with our share repurchases under our share repurchase program or fund future business acquisitions. 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, strategy or meet our future long-term liquidity requirements.
Cash, Restricted Cash and Cash Flows
The following table sets forth our net cash provided by (used in) operating, investing and financing activities during the years ended December 31, 2023 and 2022, respectively.
Year Ended December 31,
(in thousands)
2023 2022
Net cash provided by operating activities
$ 374,742 $ 300,429
Net cash used in investing activities
$ (384,127) $ (349,745)
Net cash (used in) provided by financing activities
$ (46,123) $ 26,260
Operating Activities
Net cash provided by operating activities was $374.7 million for the year ended December 31, 2023, as compared to $300.4 million for the year ended December 31, 2022. The net increase of $74.3 million was primarily due to the improvement in our net income, resulting from the increase in our existing and new customers' activity levels, resulting in higher demand for completion services, increased operational efficiencies and the addition of wireline operations . 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, partially offset by increases in inventories and prepaid expenses.
Investing Activities
Net cash used in investing activities increased to $384.1 million for the year ended December 31, 2023, from $349.7 million for the year ended December 31, 2022. The increase was primarily attributable to maintenance capital expenditures and our investment in lower emissions Tier IV DGB dual-fuel equipment (conversion of Tier II equipment to Tier IV DGB equipment and new Tier IV DGB equipment).
The following table summarizes our capital expenditures incurred by reportable segment for the periods indicated:
Year Ended December 31,
(in thousands) 2023 2022
Reportable Segments:
Hydraulic Fracturing $ 294,377 $ 347,757
Wireline 12,203 2,265
All Other (1)
3,440 9,645
Reconciling Items (2)
— 5,649
Total capital expenditures $ 310,020 $ 365,316
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(1) All Other includes our cementing operating segment and our disposed coiled tubing operations.
(2) Reconciling Items include our corporate facilities.
Financing Activities
Net cash used in financing activities was $46.1 million for the year ended December 31, 2023, compared to net cash provided by of $26.3 million for the year ended December 31, 2022. The net increase was primarily driven by share repurchases of $51.7 million, repayments of borrowings of $15.0 million and payments of finance lease obligation of $4.7 million.
Credit Facility and Other Financing Arrangements
Our revolving credit facility, as amended and restated in April 2022, prior to giving effect to the amendment to the revolving credit facility in June 2023, had a total borrowing capacity of $150.0 million. The revolving credit facility had 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 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) $10.0 million. Under the revolving credit facility we were 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.
Effective June 2, 2023, the Company entered into an amendment to its amended and restated revolving credit facility the revolving credit facility (as amended and restated in April 2022, as amended in June 2023 and as may be amended further, "ABL Credit Facility"). The amendment increased the borrowing capacity under the ABL Credit Facility to $225.0 million (subject to the Borrowing Base limit), and extended the maturity date to June 2, 2028. The ABL Credit Facility has a borrowing base of the sum of 85% to 90% of monthly eligible accounts receivable and 80% of eligible unbilled accounts (up to a maximum of 25% of the Borrowing Base) less customary reserves (the "Borrowing Base"), in each case, depending on the credit ratings of our accounts receivable counterparties, as redetermined monthly. The Borrowing Base as of December 31, 2023, was approximately $152.0 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) $15.0 million. Under the ABL Credit 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 or 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 1.75% to 2.25% for SOFR loans and 0.75% to 1.25% 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 December 31, 2023 and 2022 , we had outstanding borrowings under our ABL Credit Facility of $45.0 million and $30.0 million, respectively.
Off Balance Sheet Arrangements
We had no material off balance sheet arrangements as of December 31, 2023.
Capital Requirements, Future Sources and Use of Cash
Capital expenditures incurred were $310.0 million during the year ended December 31, 2023, as compared to $365.3 million during the year ended December 31, 2022. The significant portion of our total capital expenditures incurred during the year ended December 31, 2023 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 2024 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. 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. Based on our current plan and projected activity levels for 2024, we expect our capital expenditures to range between $200 million to $250 million. We could incur significant additional capital expenditures if our projected activity levels increase during the course of the year, inflation and supply chain tightness continues 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.
Contractual Obligations
The following table presents our contractual obligations and other commitments as of December 31, 2023:
(in thousands)
Period
Total 1 year or less More than 1 year
ABL Credit Facility (1)
$ 45,000 $ — $ 45,000
Operating leases (2)(3)
110,083 33,680 76,403
Finance lease (4)
52,534 19,872 32,662
Sand commitment (5)
17,659 17,659 —
Par Five deferred cash consideration (6)
3,180 — 3,180
Total $ 228,456 $ 71,211 $ 157,245
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(1) Exclusive of future commitment fees, amortization of deferred financing costs, interest expense or other fees on our ABL Credit Facility because obligations thereunder are floating rate instruments and we cannot determine with accuracy the timing of future loan advances, repayments of future interest rates to be changed. However, assuming a weighted average interest rate of 6.69% , and that our ABL Credit Facility debt balance remains the same, our estimated annual interest payment will be $3.0 million.
(2) Operating leases exclude short-term leases and other commitments (see Note 17. Leases and Note 18. Commitments and Contingencies in the financial statements for additional disclosures).
(3) Includes our leases for FORCE SM electric-powered hydraulic fracturing fleets (240,000 HHP). We expect to receive the remaining equipment under these leases in the first half of 2024.
(4) Finance lease for certain power generation equipment (70 MW) to support electric-powered hydraulic fracturing equipment .
(5) Relates to a take-or-pay sand commitment with one of our sand vendors.
(6) Represents the unpaid portion of the purchase consideration on our acquisition of Par Five assets to be used to cover the amount by which the estimated purchase price exceeds the final purchase price, if any.
We enter into other purchase agreements with Sand Suppliers to secure supply of sand in the normal course of our business. The agreements with the Sand Suppliers require that we purchase minimum volume of sand, based primarily on a certain percentage of our sand requirements from our customers or in certain situations based on predetermined fixed minimum volumes, otherwise certain penalties (shortfall fees) may be charged. The shortfall fee represents liquidated damages and is either a fixed percentage of the purchase price for the mi nimum volumes or a fixed price per ton of unpurchased volumes. Our current agreements with Sand Suppliers expire at different times prior to December 31, 2025 . Our agreed upon sand requirements or minimum volumes are based on certain future events such as our customer demand, which cannot be reasonably estimated. If the activity level of our customers declines and the future demand for our services is materially and adversely affected, we may be required to pay for more sand from one of our Sand Suppliers than we need in the performance of our services, regardless of whether we take physical delivery of such sand. In such an event, we may be required to pay shortfall fees or other penalties under the purchase agreement, which could have a material adverse effect on our business, financial condition, or results of operations.
Recent Accounting Pronouncements
Disclosure concerning recently issued accounting standards is incorporated by reference to " Note 2- Significant Accounting Policies " of our Consolidated Financial Statements contained in this Annual Report.
Critical Accounting Policies and Estimates
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The discussion and analysis of our financial condition and results of operations is based on our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the dates of the financial statements and the reported revenues and expenses during the years. We evaluate these estimates and assumptions on an ongoing basis and base our estimates on historical experience, current conditions and various other assumptions that we believe to be reasonable under the circumstances. The results of these estimates form the basis for making judgments about the carrying values of assets and liabilities as well as identifying and assessing the accounting treatment with respect to commitments and contingencies. Our actual results may materially differ from these estimates.
Listed below are the accounting policies that we believe are critical to our financial statements due to the degree of uncertainty regarding the estimates or assumptions involved, and that we believe are critical to the understanding of our operations.
Property and Equipment
Our property and equipment are recorded at cost, less accumulated depreciation.
Upon sale or retirement of property and equipment, the cost and related accumulated depreciation are removed from the balance sheet and the net amount, less proceeds from disposal, is recognized as a gain or loss in earnings.
We primarily retire certain components of equipment such as fluid ends and power ends, rather than the entire pieces of equipment. The associated loss is recorded in our statement of operations as part of net loss on disposal of assets, which was $73.0 million , $102.1 million and $64.6 million for the years ended December 31, 2023, 2022 and 2021, respectively.
The estimated useful lives and salvage values of property and equipment is subject to key assumptions such as maintenance, utilization and job variation. Unanticipated future changes in these assumptions could negatively or positively impact our net income (loss). A 10% change in the useful lives of our property and equipment would have resulted in approximately $17.0 million impact on pre-tax loss during the year ended December 31, 2023. Depreciation of property and equipment is provided on the straight‑line method over estimated useful lives as shown in the table below.
Land
Indefinite
Buildings and property improvements
5 - 30 years
Vehicles
1 ‑ 5 years
Equipment
1 ‑ 22 years
Leasehold improvements
5 ‑ 20 years
Impairment of Long-Lived Assets
In accordance with the Financial Accounting Standards Board Accounting Standards Codification ( " ASC " ) 360 regarding Accounting for the Impairment or Disposal of Long‑Lived Assets , we review the long‑lived assets including intangible assets to be held and used whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future undiscounted cash flows attributable to the assets is less than the carrying amount of such assets. In this circumstance, we recognize an impairment loss for the amount by which the carrying amount of the assets exceeds the estimated fair value of the asset. Our cash flow forecasts require us to make certain judgments regarding long‑term forecasts of future revenue and costs and cash flows related to the assets subject to review. The significant assumption in our cash flow forecasts is our estimated equipment utilization and profitability. The significant assumption is uncertain in that it is driven by future demand for our services and utilization, which could be impacted by crude oil market prices, future market conditions and technological advancements. Our fair value estimates for certain long‑lived assets require us to use significant other observable inputs, including assumptions related to market based on recent auction sales or selling prices of comparable equipment. The estimates of fair value are also subject to significant variability, are sensitive to changes in market conditions, and are reasonably likely to change in the future.
If the crude oil market declines or the demand for our services does n ot recover, and if our equipment remains idle or underutilized, the estimated fair value of such equipment may decline, which could result in future impairment charges. Though the impacts of variations in any of these factors can have compounding or offsetting impacts, a 10% decline in the estimated future cash flows of our existing asset groups will not indicate an impairment.
In 2022, we recorded impairment expense of $57.5 million on our DuraStim® electric-powered hydraulic fracturing equipment within the hydraulic fracturing operating segment .
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Goodwill and Other Intangible Assets
Goodwill is the excess of the consideration transferred over the fair value of the tangible and identifiable intangible assets and liabilities recognized. Goodwill is not amortized. We perform an annual impairment test of goodwill and intangible assets as of December 31, or more frequently if circumstances indicate that impairment may exist.
In connection with the Silvertip Acquisition, we added $23.6 million of goodwill during the year ended December 31, 2022. There were no additions to goodwill during the year ended December 31, 2023. The wireline operating segment is the only segment with goodwill at December 31, 2023 and 2022. There were no goodwill impairment losses during the years ended December 31, 2023 and 2022. We performed our annual goodwill impairment test in accordance with ASC 350, Intangibles—Goodwill and Other , on December 31, 2023, at which time, we determined that the fair value of our wireline reporting unit was substantially in excess of its carrying value. The quantitative impairment test we perform for goodwill utilizes certain assumptions, including forecasted equipment utilization, pricing and cost assumptions. Our discounted cash flow analysis includes significant assumptions regarding discount rates, utilization, expected profitability margin, forecasted maintenance capital expenditures, and the timing of expected cash flow. As such, our goodwill analysis incorporates inherent uncertainties that are difficult to predict in volatile economic environments and could result in impairment charges in future periods if actual results materially differ from the estimated assumptions utilized in our forecast. As of December 31, 2023 and 2022, our goodwill carrying value was $23.6 million and $23.6 million, respectively.
Intangible assets consist of customer relationships and trademark/trade name. In connection with the Silvertip Acquisition, we added intangible assets consisting of $46.5 million of customer relationships and $10.8 million of trademark/trade name during the year ended December 31, 2022. Intangible assets are amortized on a straight‑line basis with an estimated useful life of ten years. Our estimated useful life could be sensitive to changes in market conditions and management’s judgment, and are likely to change in the future if certain events occur. Presently, there are no events or circumstances that will cause us to believe that our estimated useful life for our intangible assets are likely to change.
Income Taxes
Income taxes are accounted for under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the consolidated financial statements. Under this method, deferred tax assets and liabilities are determined on the basis of differences between the consolidated financial statements and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.
We recognize deferred tax assets to the extent that we believe these assets are more likely than not to be realized. In making such a determination, we consider all positive and negative evidence, including future reversals of existing taxable temporary differences, projected future taxable income, and the results of recent operations. If we determine that we would not be able to fully realize our deferred tax assets in the future in excess of their net recorded amount, we would record a valuation allowance, which would increase our provision for income taxes. In determining our need for a valuation allowance as of December 31, 2023, we have considered and made judgments and estimates regarding estimated future taxable income. These estimates and judgments include some degree of uncertainty and changes in these estimates and assumptions could require us to record additional valuation allowances for our deferred tax assets and the ultimate realization of tax assets depends on the generation of sufficient taxable income.
Our methodology for recording income taxes requires a significant amount of judgment in the use of assumptions and estimates. Additionally, we forecast certain tax elements, such as future taxable income, as well as evaluate the feasibility of implementing tax planning strategies. Given the inherent uncertainty involved with the use of such variables, there can be significant variation between anticipated and actual results. Unforeseen events may significantly impact these variables, and changes to these variables could have a material impact on our income tax accounts. The final determination of our income tax liabilities involves the interpretation of local tax laws and related authorities in each jurisdiction. Changes in the operating environments, including changes in tax law, could impact the determination of our income tax liabilities for a tax year.
Share Repurchases
All shares of common stock repurchased through the Company's share repurchase program are retired upon repurchase. The Company accounts for the purchase price of repurchased common stock in excess of par value ($0.001 per share of common stock) as a reduction of additional paid-in capital, and will continue to do so until additional paid-in capital is reduced to zero. Thereafter, any excess purchase price will be recorded as a reduction of retained earnings.
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