PATTERSON UTI ENERGY INC (PTEN)

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

Management Overview — We are a Houston, Texas-based leading provider of drilling and completion services to oil and natural gas exploration and production companies in the United States and other select countries, including contract drilling services, integrated well completion services and directional drilling services in the United States, and specialized drill bit solutions in the United States, Middle East and many other regions around the world. We operate under three reportable business segments: (i) drilling services, (ii) completion services, and (iii) drilling products.

Drilling Services

Our contract drilling business operates in the continental United States and internationally in Colombia and Ecuador and, from time to time, we pursue contract drilling opportunities in other select markets. We also provide a comprehensive suite of directional drilling services in most major producing onshore oil and natural gas basins in the United States, and we provide services that improve the statistical accuracy of wellbore placement for directional and horizontal wells. We also service and re-certify equipment for drilling contractors, and we provide electrical controls and automation to the energy, marine and mining industries, in North America and other select markets.

We have addressed our customers’ needs for drilling horizontal wells in shale and other unconventional resource plays by improving the capabilities of our drilling fleet. The U.S. land rig industry has in recent years referred to certain high specification rigs as “super-spec” rigs, which we consider to be at least a 1,500 horsepower, AC-powered rig that has at least a 750,000-pound hookload, a 7,500-psi circulating system, and is pad-capable. Due to evolving customer preferences, we refer to certain premium rigs as “Tier-1, super spec” rigs, which we consider as being a super-spec rig that also has a third mud pump and raised drawworks that allows for more clearance underneath the rig floor. As of December 31, 2024, our rig fleet included 135 Tier-1, super-spec rigs.

Completion Services

Our well completion services business consists of services for hydraulic fracturing, wireline and pumping, completion support, and cementing. It also includes our power solutions natural gas fueling business and our proppant last mile logistics and storage business. Our completion services business operates in several of the most active basins in the continental United States including the Permian, the Marcellus Shale/Utica, the Eagle Ford, Mid-Continental, Haynesville, and the Bakken/Rockies.

To address evolving customer preferences for emissions-reducing equipment, we have invested in natural gas-powered equipment, including electric, direct drive, and dual fuel pumps, to replace legacy diesel completion services equipment.

Drilling Products

We serve the energy and mining markets by manufacturing and distributing drill bits throughout North America and internationally in over 30 countries. Our drilling equipment is used in oil and natural gas exploration and production and in mining operations. We have manufacturing and repair facilities located in Fort Worth, Texas, Leduc, Alberta and Saudi Arabia and repair facilities located in Argentina, Colombia and Oman.

Recent Developments in Market Conditions and Outlook — Commodity prices have historically been volatile but have been relatively range-bound since the end of 2022. The current demand for equipment and services remains impacted by macro conditions, including commodity prices, geopolitical environment, inflationary pressures, economic conditions in the United States and elsewhere, as well as customer consolidation and focus by exploration and production companies and service companies on capital returns.

Oil prices averaged $70.73 per barrel in the fourth quarter of 2024 and closed at $73.52 per barrel on February 3, 2025. Natural gas prices (based on the Henry Hub Spot Market Price) averaged $2.45 per MMBtu in the fourth quarter of 2024 and closed at $3.30 per MMBtu on February 3, 2025.

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Quarterly average oil prices and our quarterly average number of rigs operating in the United States for 2022, 2023 and 2024 are as follows:

(1)The average oil price represents the average monthly WTI spot price as reported by the United States Energy Information Administration.

(2)A rig is considered to be operating if it is earning revenue pursuant to a contract on a given day.

In our drilling services segment, our average active rig count in the United States for the fourth quarter of 2024 was 105 rigs. This was a decrease from our average active rig count for the third quarter of 2024 of 107 rigs. Our active rig count in the United States at December 31, 2024 of 103 rigs was less than the rig count of 121 rigs at December 31, 2023, reflecting the industry-wide activity declines due to increased drilling efficiencies and market consolidation. We expect our rig count in the United States will average 106 rigs in the first quarter of 2025. Term contracts help support our operating rig count. Based on contracts in place in the United States as of February 5, 2025, we expect an average of 64 rigs operating under term contracts during the first quarter of 2025 and an average of 40 rigs operating under term contracts during 2025.

We maintain a backlog of commitments for contract drilling services under term contracts, which we define as contracts with a duration of six months or more. Our contract drilling backlog in the United States as of December 31, 2024 and 2023 was approximately $426 million and $700 million, respectively. Approximately 7.1% of our total contract drilling backlog in the United States at December 31, 2024 is reasonably expected to remain after 2025. See Note 3 of Notes to consolidated financial statements in Item 8 of this Report and “Item 1A. Risk Factors – Our current backlog of contract drilling revenue may decline and may not ultimately be realized, as fixed-term contracts may in certain instances be terminated without an early termination payment.”

During the fourth quarter of 2024, our completion services segment was impacted by several long-term dedicated customers reducing sequential completion activity after meeting their annual production targets. We expect a seasonal uptick in activity during the first quarter of 2025 as customer budgets reset with the start of the new year.

Activity in our drilling products segment was relatively steady in 2024 compared to the prior year. Drilling products demand is expected to remain steady through the first quarter, given the expectation for a steady U.S. market and continued growth in international markets.

During the fourth quarter, we performed work pursuant to an integrated drilling and completion arrangement that included performance incentives, and we are working to expand customer adoption of these types of arrangements.

Cash capital expenditures for 2024 totaled $678 million. This was an increase from the $616 million of cash capital expenditures in 2023 due to a full year of investing in and maintaining assets related to the NexTier merger and the Ulterra acquisition. The incremental capital spending related to these assets was partially offset by a decrease in business activity in 2024. Additionally, we received proceeds from sale of assets or idle equipment of $25.8 million and $26.5 million in 2024 and 2023, respectively. Based on our current outlook for activity, we expect our capital expenditures for 2025 to be approximately $600 million.

Recent Developments in Joint Ventures and Business Combinations — In December 2024, one of our subsidiaries closed a previously announced joint venture with subsidiaries of ADNOC Drilling and SLB. Our subsidiary holds a 15 percent interest in a newly created company named Turnwell Industries, which has been awarded a contract to drill and complete 144 unconventional wells for ADNOC. In exchange for the minority equity interest, we are providing unconventional drilling and completion expertise to Turnwell, as well as a limited cash contribution to fund our portion of initial working capital.

On September 1, 2023, we completed our merger (the “NexTier merger”) with NexTier Oilfield Solutions Inc. ("NexTier"). Each share of common stock of NexTier issued and outstanding immediately prior to the effective time (including outstanding restricted

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shares) was converted into the right to receive 0.752 shares of our common stock, which based on the closing price of our common stock of $14.91 on September 1, 2023, valued the transaction at approximately $2.8 billion, including the assumption of debt.

On August 14, 2023, we completed our acquisition (the “Ulterra acquisition”) of Ulterra Drilling Technologies, L.P. ("Ulterra"). Total consideration for the acquisition included the issuance of 34.9 million shares of our common stock and payment of approximately $373 million of cash (after purchase price adjustment), which based on the closing price of our common stock of $14.94 on August 14, 2023, valued the transaction at closing at approximately $894 million.

Recent Developments in Debt Financing — On January 31, 2025, we entered into the Second Amended and Restated Credit Agreement with the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent, and the other parties thereto (the “Credit Agreement”). The Credit Agreement amended and restated our Amended and Restated Credit Agreement dated as of March 27, 2018 (as amended, restated, supplemented or otherwise modified at December 31, 2024, the “Prior Credit Agreement”). The commitments under the Credit Agreement are $500 million, and the loans and commitments under the Credit Agreement mature on January 31, 2030.

The Credit Agreement provides for a committed senior unsecured credit facility that permits aggregate revolving credit borrowings of up to $500 million, with a letter of credit sub-facility of $100 million and a swing line sub-facility that, at any time outstanding, is limited to the lesser of $50 million and the amount of the swing line provider’s unused commitment. Subject to customary conditions, we may request that the lenders’ aggregate commitments be increased by up to $200 million, not to exceed total commitments of $700 million. For a description of the Credit Agreement, see “Liquidity and Capital Resources” included in Part II, Item 7— “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Report.

As of December 31, 2024, we had no borrowings outstanding under our Prior Credit Agreement. We had $2.1 million in letters of credit outstanding under the Prior Credit Agreement at December 31, 2024 and, as a result, had available borrowing capacity of approximately $613 million under the Prior Credit Agreement at that date.

On September 13, 2023, we completed the offering of $400 million in aggregate principal amount of 7.15% Senior Notes due 2033 (the “2033 Notes”). The net proceeds before offering expenses were approximately $396 million, which we used to repay amounts outstanding under our Prior Credit Agreement (as defined below).

Impact on our Business from Oil and Natural Gas Prices and Other Factors — Our revenues, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas, expectations about future prices, and upon our customers’ ability to access, and willingness to deploy, capital to fund their operating and capital expenditures. During periods of improved oil and natural gas prices, the capital spending budgets of oil and natural gas operators tend to expand, which generally results in increased demand for our services. Conversely, in periods when oil and natural gas prices are relatively low or when our customers have a reduced ability to access, or willingness to deploy capital, the demand for our services generally weakens, and we experience downward pressure on pricing for our services. Even during periods of historically moderate or high prices for oil and natural gas, companies exploring for oil and natural gas may cancel or curtail programs or reduce their levels of capital expenditures for exploration and production for a variety of reasons, including the depletion of capital expenditure budgets and/or meeting annual drilling and completion targets, which could reduce demand for our services. We may also be impacted by delayed customer payments and payment defaults associated with customer liquidity issues and bankruptcies.

The North American oil and natural gas services industry is cyclical and, at times, experiences downturns in demand. During these periods, there has been substantially more oil and natural gas service equipment available than necessary to meet demand. As a result, oil and natural gas service contractors have had difficulty sustaining profit margins and, at times, have incurred losses during the downturn periods. We cannot predict either the future level of demand for our oil and natural gas services or future conditions in the oil and natural gas service businesses.

In addition to the dependence on oil and natural gas prices and demand for our services, we are highly impacted by operational risks, competition, labor issues, weather, the availability, from time to time, of products used in our businesses, supplier delays and various other factors that could materially adversely affect our business, financial condition, cash flows and results of operations. See “Risk Factors” in Item 1A of this Report.

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For the three years ended December 31, 2024, our operating revenues consisted of the following (dollars in thousands):

Results of Operations

Effective as of the third quarter of 2023, we revised our reportable segments to align with certain changes in how our Chief Operating Decision Maker (“CODM”) manages and allocates resources to our business as a result of the Ulterra acquisition and NexTier merger. We now have the following reportable business segments: (i) drilling services, (ii) completion services and (iii) drilling products.

Comparison of the years ended December 31, 2023 and 2022

A discussion of our financial condition and results of operations for the fiscal year ended December 31, 2023 compared to the fiscal year ended December 31, 2022 is included in Part II, Item 7— “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the fiscal year ended December 31, 2023, filed with the SEC on February 27, 2024.

Comparison of the years ended December 31, 2024 and 2023

The following tables summarize results of operations by business segment for the years ended December 31, 2024 and 2023:

(1)Drilling services segment represents our contract drilling, directional drilling, oilfield technology and electrical controls and automation businesses.

(2)Adjusted gross profit is defined as revenues less direct operating costs (excluding depreciation, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross profit to adjusted gross profit by segment.

(3)Operational data relates to our contract drilling business. A rig is considered to be operating if it is earning revenue pursuant to a contract on a given day.

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Total revenues and direct operating costs decreased primarily due to a decrease in operating days in our contract drilling business within the United States. Average revenue per operating day remained relatively flat while average direct operating costs per operating day increased slightly. The decline in operating days impacted the fixed cost leverage for U.S. drilling rigs.

The decrease in operating days for our U.S. contract drilling business reflects the industry-wide activity declines due to increased drilling efficiencies and market consolidation.

Depreciation, amortization and impairment expense increased primarily due to a charge of $114 million related to the abandonment of 42 legacy, non-Tier-1 super-spec drilling rigs and related equipment. See Note 6 of Notes to consolidated financial statements for additional information.

Capital expenditures decreased primarily due to reduced investment in our ancillary drilling services not included within our contract drilling business and timing of order placement.

(1)Completion services represents the combination of well completion business from the NexTier merger and our legacy pressure pumping business.

(2)Adjusted gross profit is defined as revenues less direct operating costs (excluding depreciation, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross profit to adjusted gross profit by segment.

The changes in the results of our completion services segment for the year ended December 31, 2024 as compared to December 31, 2023 can be primarily attributed to the NexTier merger, which closed on September 1, 2023. The NexTier merger had a material impact on our reported results of operations. The results for the year ended December 31, 2024 represent the combination of the well completion business from the NexTier merger and our legacy pressure pumping business. Due to the full integration of our legacy pressure pumping business into the NexTier legal entity in the first quarter of 2024, we are unable to provide a meaningful year-over-year comparison excluding the impact of the NexTier merger.

During the year ended December 31, 2024, we recorded an $885 million impairment charge to goodwill associated with our completion services reporting unit. See Note 7 of Notes to consolidated financial statements for additional information.

Other operating income, net in 2024 was due to gain on legal settlements.

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(1)Adjusted gross profit is defined as revenues less direct operating costs (excluding depreciation, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross profit to adjusted gross profit by segment.

The changes in the results of our drilling products segment for the year ended December 31, 2024 as compared to December 31, 2023 are attributable to the Ulterra acquisition, which closed on August 14, 2023. As such, there was no meaningful year-over-year comparison.

Direct operating costs and depreciation, amortization and impairment expense were approximately $7.9 million and $17.7 million higher than they would have otherwise been for the year ended December 31, 2024, respectively, as a result of the step up to fair value of our drill bits in accordance with purchase accounting. Direct operating costs and depreciation, amortization and impairment expense were approximately $11.0 million and $18.0 million higher than they would have otherwise been for the year ended December 31, 2023, respectively, as a result of the step up to fair value of our drill bits in accordance with purchase accounting.

(1)Adjusted gross profit is defined as revenues less direct operating costs (excluding depreciation, depletion, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross profit to adjusted gross profit by segment.

Revenue decreased due to a lower volume of services provided by our oilfield rentals business.

Depreciation, depletion, amortization and impairment expense decreased primarily due to a $7.0 million impairment recorded in our oil and natural gas business in 2023 compared to a $3.8 million impairment in 2024.

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Selling, general and administrative expense increased primarily due to the reorganization of acquired Ulterra and NexTier support personnel to corporate following the NexTier merger and the Ulterra acquisition.

Merger and integration expense decreased due to the timing of the NexTier merger and the Ulterra acquisition, which both closed in the third quarter of 2023.

The $22.6 million change in other operating income, net was primarily due to a $5.2 million favorable legal settlement and a $6.5 million reversal of cumulative compensation costs associated with certain performance-based restricted stock units in 2023. Additionally, there was a $5.8 million credit loss expense in 2024 due to a deterioration in the financial condition of a customer.

Interest expense increased primarily due to the offering of 2033 Notes in the third quarter of 2023. See Note 9 of Notes to consolidated financial statements for additional information on our long-term debt.

The decrease in capital expenditures was primarily due to the purchase of an aircraft in 2023.

Income Taxes

The effective tax rate decreased to (1.0)% for 2024 compared to 19.9% for 2023. Our effective income tax rate fluctuates based on, among other factors, changes in pre-tax income in countries with varying statutory tax rates, changes in valuation allowances, and the impacts of various other permanent adjustments. The impact of goodwill impairments that are not deductible for income tax had a significant impact on our effective tax rate for the year ended December 31, 2024.

We continue to monitor income tax developments in the United States and other countries where we have legal entities. We will incorporate into our future financial statements the impacts, if any, of future regulations and additional authoritative guidance when finalized.

Liquidity and Capital Resources

Our primary sources of liquidity are cash and cash equivalents, availability under our revolving credit facility and cash provided by operating activities. As of December 31, 2024, we had approximately $453 million in working capital, including $239 million of cash and cash equivalents, and approximately $613 million available under the Prior Credit Agreement.

On January 31, 2025, we entered into the Credit Agreement, which amended and restated the Prior Credit Agreement. The commitments under the Credit Agreement are $500 million, and the loans and commitments under the Credit Agreement mature on January 31, 2030.

The Credit Agreement provides for a committed senior unsecured credit facility that permits aggregate revolving credit borrowings of up to $500 million, with a letter of credit sub-facility of $100 million and a swing line sub-facility that, at any time outstanding, is limited to the lesser of $50 million and the amount of the swing line provider’s unused commitment. Subject to customary conditions, we may request that the lenders’ aggregate commitments be increased by up to $200 million, not to exceed total commitments of $700 million.

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Loans under the Credit Agreement bear interest by reference, at our election, to the SOFR rate (in addition to a 0.10% per annum adjustment) or base rate, in each case subject to a 0% floor. The applicable margin on SOFR rate loans varies from 1.25% to 2.25% and the applicable margin on base rate loans varies from 0.25% to 1.25%, in each case determined based on our credit rating. A letter of credit fee is payable by us equal to the applicable margin for SOFR rate loans times the daily amount available to be drawn under outstanding letters of credit. The commitment fee rate payable to the lenders varies from 0.150% to 0.350% based on our credit rating.

None of our subsidiaries are currently required to be a guarantor under the Credit Agreement. However, if any subsidiary guarantees or incurs debt, which does not qualify for certain limited exceptions and is otherwise, in the aggregate with all other similar debt, in excess of Priority Debt (as defined in the Credit Agreement), such subsidiary is required to become a guarantor under the Credit Agreement.

The Credit Agreement contains representations, warranties, affirmative and negative covenants and events of default and associated remedies that we believe are customary for agreements of this nature, including certain restrictions on our ability and the ability of each of our subsidiaries to grant liens and on the ability of each of our non-guarantor subsidiaries to incur debt. If our credit rating is below investment grade at both Moody’s and S&P, we will become subject to a restricted payment covenant, which would generally require us to have a Pro Forma Debt Service Coverage Ratio (as defined in the Credit Agreement) greater than or equal to 1.50 to 1.00 immediately before and immediately after making any restricted payment. Restricted payments include, among other things, dividend payments, repurchases of our common stock, distributions to holders of our common stock or any other payment or other distribution to third parties on account of our or our subsidiaries’ equity interests. Our credit rating is currently investment grade at both credit rating agencies. The Credit Agreement also requires that our total debt to capitalization ratio, expressed as a percentage, not exceed 50% as of the last day of each fiscal quarter. The Credit Agreement generally defines the total debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the end of the most recently ended fiscal quarter. We were in compliance with the covenants under the Prior Credit Agreement at December 31, 2024.

On March 16, 2015, we entered into a Reimbursement Agreement (as amended from time to time, the “Reimbursement Agreement”) with The Bank of Nova Scotia (“Scotiabank”), pursuant to which we may from time to time request that Scotiabank issue an unspecified amount of letters of credit. As of December 31, 2024, we had $38.8 million in letters of credit outstanding under the Reimbursement Agreement.

Under the terms of the Reimbursement Agreement, we will reimburse Scotiabank on demand for any amounts that Scotiabank has disbursed under any of our letters of credit issued thereunder. Fees, charges and other reasonable expenses for the issuance of letters of credit are payable by us at the time of issuance at such rates and amounts as are in accordance with Scotiabank’s prevailing practice. We are obligated to pay to Scotiabank interest on all amounts not paid by us on the date of demand or when otherwise due at the Prime rate plus 2.00% per annum, calculated daily and payable monthly, in arrears, on the basis of a calendar year for the actual number of days elapsed, with interest on overdue interest at the same rate as on the reimbursement amounts. A letter of credit fee is payable by us equal to 1.50% times the amount of outstanding letters of credit.

We have also agreed that if obligations under the Credit Agreement are secured by liens on any of our or our subsidiaries’ property, then our reimbursement obligations and (to the extent similar obligations would be secured under the Credit Agreement) other obligations under the Reimbursement Agreement and any letters of credit will be equally and ratably secured by all property subject to such liens securing the Credit Agreement.

Pursuant to a Continuing Guaranty dated as of March 16, 2015, our payment obligations under the Reimbursement Agreement are jointly and severally guaranteed as to payment and not as to collection by our subsidiaries that from time to time guarantee payment under the Credit Agreement. None of our subsidiaries are currently required to guarantee payment under the Credit Agreement.

We had $42.9 million of outstanding letters of credit at December 31, 2024, which was comprised of $38.8 million outstanding under the Reimbursement Agreement, $2.1 million outstanding under the Prior Credit Agreement, and $2.0 million outstanding with financial institutions providing for short-term borrowing capacity, overdraft protection and bonding requirements. We maintain these letters of credit primarily for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under terms of the underlying insurance contracts and compliance with contractual obligations. These letters of credit expire annually at various times during the year and are typically renewed. As of December 31, 2024, no amounts had been drawn under the letters of credit.

Our outstanding long-term debt at December 31, 2024 was $1.2 billion and consisted of $483 million of our 2028 Notes, $345 million of our 2029 Notes, $400 million of our 2033 Notes and $6.4 million of Equipment Loans. We were in compliance with all covenants under the associated agreements and indentures at December 31, 2024.

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For a full description of the Prior Credit Agreement, the Reimbursement Agreement, the 2028 Notes, the 2029 Notes, and the 2033 Notes, see Note 9 of Notes to consolidated financial statements included as a part of Item 8 of this Report.

Cash Requirements

We believe our current liquidity, together with cash expected to be generated from operations, should provide us with sufficient ability to fund our current plans to maintain and make improvements to our existing equipment, service our debt, pay cash dividends and repurchase our common stock and senior notes for at least the next 12 months.

If we pursue other opportunities that require capital, we believe we would be able to satisfy these needs through a combination of working capital, cash flows from operating activities, borrowing capacity under our revolving credit facility or additional debt or equity financing. However, there can be no assurance that such capital will be available on reasonable terms, if at all.

A portion of our capital expenditures can be adjusted and managed by us to match market demand and activity levels. Based on our current outlook for activity, we expect our capital expenditures for 2025 to be approximately $600 million. The majority of these expenditures are expected to be used for normal, recurring items necessary to support our business.

We anticipate $52.2 million of expenditures in 2025 related to various contractual obligations such as certain commitments to purchase proppants and lease liabilities.

As of December 31, 2024, we had working capital of $453 million, including cash, cash equivalents and restricted cash of $241 million, compared to working capital of $435 million, including cash, cash equivalents and restricted cash of $193 million, at December 31, 2023.

During 2024, our sources of cash flow included:

•$1.2 billion from operating activities, and

•$25.8 million in proceeds from the disposal of property and equipment.

During 2024, our uses of cash flow included:

•$678 million to make capital expenditures for the betterment and refurbishment of drilling services and completion services equipment and, to a much lesser extent, equipment for our other businesses, to acquire and procure equipment to support our drilling services, completion services, drilling products, oilfield rentals and manufacturing operations and to fund investments in oil and natural gas properties on a non-operating working interest basis,

•$290 million for repurchases of our common stock,

•$127 million to pay dividends on our common stock,

•$45.5 million for payments related to finance leases, and

•$17.5 million for other investing and financing activities.

We paid cash dividends during the year ended December 31, 2024 as follows:

On February 5, 2025, our Board of Directors approved a cash dividend on our common stock in the amount of $0.08 per share to be paid on March 17, 2025 to holders of record as of March 3, 2025. The amount and timing of all future dividend payments, if any, are subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of our debt agreements and other factors. Our Board of Directors may, without advance notice, reduce or suspend our dividend for any reason, including to improve our financial flexibility and position our company for long-term success. There can be no assurance that we will pay a dividend in the future.

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We may, at any time and from time to time, seek to retire or purchase our outstanding debt for cash through open-market purchases, privately negotiated transactions, redemptions or otherwise. Such repurchases, if any, will be upon such terms and at such prices as we may determine, and will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

In September 2013, our Board of Directors approved a stock buyback program. In February 2024, our Board of Directors approved an increase of the authorization under the stock buyback program to allow for an aggregate of $1.0 billion of future share repurchases. All purchases executed to date have been through open market transactions. Purchases under the buyback program are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Purchases may be made at any time without prior notice. There is no expiration date associated with the buyback program. As of December 31, 2024, we had remaining authorization to purchase approximately $759 million of our outstanding common stock under the stock buyback program. Shares of stock purchased under the buyback program are held as treasury shares.

We acquired shares of stock from employees during 2024, 2023 and 2022 that are accounted for as treasury stock. Certain of these shares were acquired to satisfy the exercise price and employees’ tax withholding obligations upon the exercise of stock options. The remainder of these shares were acquired to satisfy payroll withholding obligations upon the settlement of performance unit awards and the vesting of restricted stock units. These shares were acquired at fair market value. These acquisitions were made pursuant to the terms of the Patterson-UTI Energy, Inc. Amended and Restated 2014 Long-Term Incentive Plan, as amended (the “2014 Plan”), the Patterson-UTI Energy, Inc. 2021 Long-Term Incentive Plan (the “2021 Plan”), the NexTier Oilfield Solutions Inc. Equity and Incentive Award Plan and the NexTier Oilfield Solutions Inc. (Former C&J Energy) Management Incentive Plan, and not pursuant to the stock buyback program.

Treasury stock acquisitions during the years ended December 31, 2024, 2023 and 2022 were as follows (dollars in thousands):

As of December 31, 2024, we had unrecognized compensation costs of $42.8 million and $12.8 million related to our unvested restricted stock units and our unvested Performance Units, respectively. The weighted-average remaining vesting periods for these awards were 1.71 years and 1.04 years, respectively as of December 31, 2024. See Note 12 of Notes to consolidated financial statements in Item 8 of this Report for additional discussion regarding our stock-based compensation.

Commitments — As of December 31, 2024, we had commitments to purchase major equipment totaling approximately $65.9 million.

Our completion services segment has entered into agreements to purchase minimum quantities of proppants from certain vendors. As of December 31, 2024, the remaining minimum obligation under these agreements was approximately $19.8 million, of which approximately, $17.4 million and $2.4 million relate to 2025 and 2026, respectively.

See Note 10 of Notes to consolidated financial statements in Item 8 of this Report for additional information on our current commitments and contingencies as of December 31, 2024.

Operating lease liabilities totaled $47.6 million and finance lease liabilities totaled $25.4 million at December 31, 2024. See Note 13 of Notes to consolidated financial statements in Item 8 of this Report for additional information on our operating and finance leases as of December 31, 2024.

Trading and Investing — We have not engaged in trading activities that include high-risk securities, such as derivatives and non-exchange traded contracts. We invest cash primarily in highly liquid, short-term investments such as overnight deposits and money market accounts.

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Critical Accounting Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from such estimates. Accounting estimates and assumptions discussed in this section are those considered to be the most critical to an understanding of our financial statements because they involve significant judgments and uncertainties. We believe the following critical accounting estimates used in preparing our consolidated financial statements address all important areas where the nature of the estimates or assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change. For additional information on our accounting policies, see Note 1 of Notes to consolidated financial statements included as a part of Item 8 of this Report.

Depreciation and amortization — Our industry is very capital intensive, as property and equipment represented 51.6% of our total assets as of December 31, 2024 and depreciation, depletion, amortization and impairment represented 18.7% of our total operating costs and expenses in 2024. Our property and equipment is carried at cost less accumulated depreciation and amortization. No provision for salvage value is considered in determining depreciation of our property and equipment. We calculate depreciation and amortization on our assets based on the estimated useful lives that we believe are reasonable. The estimated useful lives are subject to key assumptions such as maintenance, utilization and job variation. These estimates may change due to a number of factors such as changes in operating conditions or advances in technology. The method of depreciation does not change whenever equipment becomes idle. Maintenance and repairs are charged to expense when incurred. Renewals and betterments which extend the life or improve existing property and equipment are capitalized.

The following table outlines a 10% change in the useful lives on our major categories of property and equipment and the impact on operating income for the year ended December 31, 2024:

Impairment of long-lived assets — We review our long-lived assets, including property and equipment and definite-lived intangible assets, for impairment whenever events or changes in circumstances indicate that the carrying amounts of certain assets may not be recovered over their estimated remaining useful lives (“triggering events”). In connection with this review, assets are grouped at the lowest level at which identifiable cash flows are largely independent of other asset groupings. We estimate the undiscounted future cash flows over the life of the respective asset or the primary asset in an asset group. These estimates of cash flows are based on historical trends in the industry as well as our expectations regarding the continuation of these trends in the future. As of December 31, 2024, no impairment was indicated for our long-lived tangible or definite-lived intangible assets. See Note 6 of Notes to consolidated financial statements included as a part of Item 8 of this Report.

While we believe our judgments and assumptions are reasonable, geopolitical instability, global or regional decreases in the demand of our services and products, or other unforeseen macroeconomic considerations could negatively impact the expected cash flows used in our recoverability tests on our asset groups. Such changes could result in impairment charges in the future, which could be material to our results of operations and financial statements as a whole.

Fair values of assets acquired and liabilities assumed in acquisitions — Assets acquired and liabilities assumed in a business combination are recorded at their estimated fair values on the date of acquisition. The difference between the purchase price amount and the net fair value of assets acquired and liabilities assumed is recognized as goodwill on the balance sheet if the purchase price exceeds the estimated net fair value or as a bargain purchase gain on the income statement if the purchase price is less than the estimated net fair value. We apply significant judgment in estimating the fair value of assets acquired and liabilities assumed, which involves the use of significant estimates and assumptions with respect to rig counts, cash flow projections, estimated economic useful lives, operating and capital cost estimates, customer attrition rates, contributory asset charges, royalty rates and discount rates. Changes in these judgments or estimates can have a material impact on the valuation of the respective assets and liabilities acquired and our results of operations in periods after acquisition, such as through depreciation and amortization expense. The allocation of the purchase price may be modified up to one year after the acquisition date as more information is obtained about the fair value of assets acquired and liabilities assumed. See Note 2 of Notes to consolidated financial statements included as a part of Item 8 of this Report.

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Goodwill — We assess goodwill at least annually on July 31, or more frequently when events and circumstances occur indicating recorded goodwill may be impaired. Goodwill is tested at the reporting unit level, which is at or one level below our operating segments. We determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying value after considering qualitative, market and other factors. Any necessary goodwill impairment is determined using a quantitative impairment test. If the resulting fair value of goodwill is less than the carrying value of goodwill, an impairment loss would be recognized for the amount of the shortfall. The fair value of a reporting unit is determined using significant unobservable inputs, or level 3 in the fair value hierarchy. These inputs are based on internal management estimates, forecasts, and significant judgment.

We determined our drilling products operating segment consists of a single reporting unit and, accordingly, goodwill acquired from the Ulterra acquisition was allocated to that reporting unit. We determined our completion services operating segment consists of two reporting units; completion services, which is primarily comprised of our hydraulic fracturing operations and other integrated service offerings, and cementing services.

Negative market indicators such as lower industry-wide drilling rig and pressure pumping fleet count forecasts, increased volatility and pricing declines in the pressure pumping market, and continued efficiency gains and technology advancements reducing operating days have led to our reduced outlook for activity. During the third quarter of 2024, we viewed the reduction in activity forecasts combined with the recent decline in the market price of our common stock as a triggering event that warranted a quantitative assessment for goodwill impairment.

We estimated the fair value of the drilling products and the completion services reporting units using the income approach. Under this approach, we used a discounted cash flow model, which utilized present values of cash flows to estimate fair value. Forecasted cash flows reflected known market conditions in the third quarter of 2024 and management’s anticipated business outlook for each reporting unit. Future cash flows were projected based on estimates of revenue growth rates, gross profit, selling, general and administrative expense, changes in working capital, and capital expenditures. The terminal period used within the discounted cash flow model for each reporting unit consisted of a 1% growth estimate. Future cash flows were then discounted using a market-participant, risk-adjusted weighted average cost of capital of 10.25% for the drilling products reporting unit and 10.75% for the completion services reporting unit. Financial and credit market volatility directly impacts our fair value measurement through the weighted average cost of capital used to determine a discount rate. During times of volatility, significant judgment must be applied to determine whether credit market changes are a short-term or long-term trend.

We estimated the fair value of the cementing services reporting unit in our completion services operating segment using a market approach. The market approach was based on trading multiples of earnings before interest, taxes, depreciation and amortization for companies comparable to the cementing services reporting unit.

The forecast for the completion services reporting unit assumed lower activity in 2025 compared to average activity levels for full year 2024 and increases in estimated activity of 2% to 8% beginning in 2026 through 2029. Those estimates were based on future drilling rig and pressure pumping fleet count forecasts during the third quarter of 2024 and estimated market share. Additionally, the forecast reflected the expectation that industry-wide pricing pressure will persist within the completions market and continue to compress adjusted gross profit. These factors negatively impacted the estimated value of the reporting unit.

Based on the results of the quantitative assessment, the fair value of the completion services reporting unit was less than its carrying value. Accordingly, we recorded an $885 million impairment charge to goodwill for the completion services reporting unit during the third quarter of 2024.

The forecast for the drilling products reporting unit assumed continued growth domestically as well as in international markets. Geopolitical instability in regions in which we expect to maintain and grow market share, a global decrease in the demand of drilling products, or other unforeseen macroeconomic considerations could negatively impact the key assumptions used in our goodwill assessment for our drilling products reporting unit.

Based on the results of the goodwill impairment tests performed during the third quarter of 2024, the fair values of the drilling products and cementing services reporting units exceeded their carrying values by approximately 13% and 73%, respectively. Accordingly, no impairment was recorded for the drilling products and cementing services reporting units.

Assuming all changes are isolated, a decrease of 100 bps in our long-term revenue growth rate for our drilling products reporting unit would reduce our estimated fair value by approximately 5%, while a 100 bps increase to our discount rate would reduce our estimated fair value by approximately 10%.

A decrease in fair value resulting from unfavorable changes to these assumptions, or others, could result in goodwill impairment in future periods that could be material to our results of operations and financial statements as a whole.

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Accruals for self-insured levels of insurance coverage — We maintain insurance coverage for fire, windstorm and other risks of physical loss to our equipment and certain other assets, employers’ liability, automobile liability, commercial general liability, workers’ compensation and insurance for other specific risks. We also self-insure a number of other risks, including loss of earnings and business interruption and most of our cybersecurity risks, and do not carry a significant amount of insurance to cover risks of underground reservoir damage. Our insurance accruals are based on claims filed and estimates of claims incurred but not reported and are developed by our management with assistance from our third-party actuary and third-party claims administrator. The insurance accruals are influenced by our past claims experience factors and by published industry development factors. If we experience insurance claims or costs above or below our historically evaluated levels, our estimates could be materially affected. The frequency and number of claims or incidents could vary significantly over time, which could materially affect our self-insurance liabilities. Additionally, the actual costs to settle the self-insurance liabilities could materially differ from the original estimates and cause us to incur additional costs in future periods associated with prior year claims. A sensitivity analysis of the impact on earnings for these periods if other assumptions had been used in recording these liabilities is not practicable given the number of underlying assumptions and the wide range of reasonably possible outcomes. See “Item 1A. Risk Factors – Our operations are subject to a number of operational risks, including environmental and weather risks, which could expose us to significant losses and damage claims. We are not fully insured against all of these risks and our contractual indemnity provisions may not fully protect us.”

Income taxes — We are subject to income taxes in the United States and other foreign jurisdictions. We compute our provision for income taxes using the asset and liability method, under which deferred tax assets and liabilities are recognized for operating loss and tax credit carryforwards and for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the results of operations in the period that includes the enactment date. In assessing the realizability of our deferred tax assets, if it is more likely than not that a portion of the deferred tax assets will not be realized in a future period, the deferred tax assets will be reduced by a valuation allowance. We believe the valuation allowance is a critical accounting estimate because it is susceptible to change from period to period, requires assumptions about our future income over the lives of the deferred tax assets, and because the impact of increasing or decreasing the valuation allowance is potentially material to our results of operations.

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.

We continue to monitor income tax developments, including OECD Pillar 2 legislation, in the United States and other countries where we have legal entities. We recognize tax benefits related to uncertain tax positions when, in our judgment, it is more likely than not that such positions will be sustained on examination, including resolutions of any related appeals or litigation, based on the technical merits. We adjust our liabilities for uncertain tax positions when our judgment changes as a result of new information previously unavailable. We routinely monitor the potential impact of these situations. As of December 31, 2024, we have no unrecognized tax benefits.

Volatility of Oil and Natural Gas Prices and its Impact on Operations and Financial Condition

Our revenues, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas and expectations about future prices, and upon our customers’ ability to access, and willingness to deploy, capital to fund their operating and capital expenditures. Commodity prices have historically been volatile, but have been relatively range-bound since the end of 2022. The current demand for equipment and services remains impacted by macro conditions, including commodity prices, geopolitical environment, inflationary pressures, economic conditions in the United States and elsewhere, as well as customer consolidation and focus by exploration and production companies and service companies on capital returns. Oil prices averaged $70.73 per barrel in the fourth quarter of 2024. Natural gas prices (based on the Henry Hub Spot Market Price) averaged $2.45 per MMBtu in the fourth quarter of 2024.

In light of these and other factors, we expect oil and natural gas prices to continue to be unpredictable and to affect our financial condition, operations and ability to access sources of capital. Higher oil and natural gas prices do not necessarily result in increased activity because demand for our services is generally driven by our customers’ expectations of future oil and natural gas prices, as well as our customers’ ability to access, and willingness to deploy, capital to fund their operating and capital expenditures. A decline in demand for oil and natural gas, prolonged low oil or natural gas prices, expectations of decreases in oil and natural gas prices or a reduction in the ability of our customers to access capital would likely result in reduced capital expenditures by our customers and

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decreased demand for our services, which could have a material adverse effect on our operating results, financial condition and cash flows. Even during periods of historically moderate or high prices for oil and natural gas, companies exploring for oil and natural gas may cancel or curtail programs or reduce their levels of capital expenditures for exploration and production for a variety of reasons, including the depletion of capital expenditure budgets and/or meeting annual drilling and completion targets, which could reduce demand for our services.

Impact of Inflation

Inflation rates have begun to moderate. However, we continue to actively monitor market trends primarily related to sourcing labor, supplies and equipment.

Recently Issued Accounting Standards

For a discussion of recently issued accounting standards, see Note 1 of Notes to consolidated financial statements included as a part of Item 8 of this Report.

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Non-GAAP Financial Measures

Adjusted EBITDA

Adjusted earnings before interest, taxes, depreciation and amortization (“Adjusted EBITDA”) is not defined by accounting principles generally accepted in the United States of America (“GAAP”). We define Adjusted EBITDA as net income (loss) plus income tax expense (benefit), net interest expense, depreciation, depletion, amortization and impairment expense (including impairment of goodwill) and merger and integration expense. We present Adjusted EBITDA as a supplemental disclosure because we believe it provides to both management and investors additional information with respect to the performance of our fundamental business activities and a comparison of the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be construed as an alternative to the GAAP measure of net income (loss). Our computations of Adjusted EBITDA may not be the same as similarly titled measures of other companies. Set forth below is a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measure of net income (loss).

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Adjusted Gross Profit

We define “Adjusted gross profit” as revenues less direct operating costs (excluding depreciation, depletion, amortization and impairment expense, which does not include impairment of goodwill). Adjusted gross profit is included as a supplemental disclosure because it is a useful indicator of our operating performance.

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

Management Overview — We are a Houston, Texas-based leading provider of drilling and completion services to oil and natural gas exploration and production companies in the United States and other select countries, including contract drilling services, integrated well completion services and directional drilling services in the United States, and specialized drill bit solutions in the United States, Middle East and many other regions around the world. We operate under three reportable business segments: (i) drilling services, (ii) completion services, and (iii) drilling products.

Drilling Services

Our contract drilling business operates in the continental United States and internationally in Colombia and, from time to time, we pursue contract drilling opportunities in other select markets. We also provide a comprehensive suite of directional drilling services in most major producing onshore oil and natural gas basins in the United States, and we provide services that improve the statistical accuracy of wellbore placement for directional and horizontal wells. We also service and re-certify equipment for drilling contractors, and we provide electrical controls and automation to the energy, marine and mining industries, in North America and other select markets.

We have addressed our customers’ needs for drilling horizontal wells in shale and other unconventional resource plays by improving the capabilities of our drilling fleet. The U.S. land rig industry has in recent years referred to certain high specification rigs as “super-spec” rigs, which we consider to be at least a 1,500 horsepower, AC-powered rig that has at least a 750,000-pound hookload, a 7,500-psi circulating system, and is pad-capable. Due to evolving customer preferences, we refer to certain premium rigs as “Tier-1, super spec” rigs, which we consider as being a super-spec rig that also has a third mud pump and raised drawworks that allows for more clearance underneath the rig floor. As of December 31, 2023, our rig fleet included 173 super-spec rigs, of which 131 were Tier-1, super-spec rigs.

Completion Services

Our well completion services business consists of services for hydraulic fracturing, wireline and pumping, completion support, and cementing. It also includes our power solutions natural gas fueling business and our proppant last mile logistics and storage business. Our completion services business operates in several of the most active basins in the continental United States including the Permian, the Marcellus Shale/Utica, the Eagle Ford, Mid-Continental, Haynesville, and the Bakken/Rockies.

To address evolving customer preferences for emissions-reducing equipment, we have invested in natural gas-powered equipment, including electric pumps, to replace legacy diesel completion services equipment.

Drilling Products

We serve the energy and mining markets by manufacturing and distributing drill bits through North America and internationally in over 30 countries. Our drilling equipment is used in oil and natural gas exploration and production and in mining operations. We have manufacturing and repair facilities located in Fort Worth, Texas, Leduc, Alberta and Saudi Arabia and repair facilities located in Argentina, Colombia and Oman.

Recent Developments in Market Conditions and Outlook — Crude oil prices and demand for drilling and completion equipment and services increased from 2021 to 2022, and industry supply of Tier-1, super-spec rigs became constrained. Commodity price volatility in the second quarter of 2023 resulted in a decline in industry activity; commodity prices subsequently increased during the third quarter before declining in the fourth quarter of 2023. The current demand for equipment and services remains dependent on macro conditions, including commodity prices, geopolitical environment, inflationary pressures, economic conditions in the United States and elsewhere, as well as customer consolidation and focus by exploration and production companies and service companies on capital returns.

Oil prices averaged $78.53 per barrel in the fourth quarter of 2023 and closed at 78.72 per barrel on February 20, 2024. Natural gas prices (based on the Henry Hub Spot Market Price) averaged $2.74 per MMBtu in the fourth quarter of 2023 and closed at $1.50 per MMBtu on February 20, 2024.

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Quarterly average oil prices and our quarterly average number of rigs operating in the United States for 2021, 2022 and 2023 are as follows:

(1)
The average oil price represents the average monthly WTI spot price as reported by the United States Energy Information Administration.

(2)
A rig is considered to be operating if it is earning revenue pursuant to a contract on a given day.

Our average active U.S. rig count for the fourth quarter of 2023 was 118 rigs. This was a decrease from our average active rig count for the third quarter of 2023 of 120 rigs. Our active U.S. rig count at December 31, 2023 of 121 rigs was less than the rig count of 132 rigs at December 31, 2022, due in large part to the decline in commodity prices and reduced demand for drilling services in the United States. We expect our rig count in the United States will average 120 rigs in the first quarter of 2024. Term contracts help support our operating rig count. Based on contracts in place in the United States as of February 14, 2024, we expect an average of 79 rigs operating under term contracts during the first quarter of 2024 and an average of 52 rigs operating under term contracts during 2024.

We maintain a backlog of commitments for contract drilling services under term contracts, which we define as contracts with a duration of six months or more. Our contract drilling backlog in the United States as of December 31, 2023 and 2022 was approximately $700 million and $830 million, respectively. Approximately 16% of our total contract drilling backlog in the United States at December 31, 2023 is reasonably expected to remain after 2024. See Note 3 of Notes to consolidated financial statements in Item 8 of this Report and “Item 1A. Risk Factors – Our current backlog of contract drilling revenue may decline and may not ultimately be realized, as fixed-term contracts may in certain instances be terminated without an early termination payment.”

Our completion services business was impacted by calendar inefficiencies during the second half of 2023 resulting from a decline in customer activity during the third quarter. Completion services activity stabilized in the fourth quarter of 2023. We believe activity will modestly decline in the first quarter of 2024.

Drilling products demand increased from the third quarter of 2023 despite a decline in the global rig count. Drilling Products demand is expected to remain steady through the first quarter, given the expectation for a steady market in the U.S. and moderate growth in international markets relative to what we saw in the fourth quarter.

Cash capital expenditures for 2023 totaled $616 million. This was an increase from the $437 million of cash capital expenditures in 2022 due largely to the Ulterra acquisition and NexTier merger in 2023. Based on our current outlook for activity, we expect our capital expenditures for 2024 to be approximately $740 million.

Recent Developments in Business Combinations — On September 1, 2023, we completed our merger (the “NexTier merger”) with NexTier Oilfield Solutions Inc. (“NexTier”). Each share of common stock of NexTier issued and outstanding immediately prior to the effective time (including outstanding restricted shares) was converted into the right to receive 0.752 shares of our common stock, which based on the closing price of our common stock of $14.91 on September 1, 2023, valued the transaction at approximately $2.8 billion, including the assumption of debt. NexTier is a predominately U.S. land-focused oilfield service provider, with a diverse set of well completion and production services across a variety of active basins.

On August 14, 2023, we completed our acquisition (the “Ulterra acquisition”) of Ulterra Drilling Technologies, L.P. (“Ulterra”). Total consideration for the acquisition included the issuance of 34.9 million shares of our common stock and payment of approximately $376 million cash, which based on the closing price of our common stock of $14.94 on August 14, 2023, valued the transaction at closing at approximately $897 million. Ulterra is a global provider of specialized drill bit solutions.

Recent Developments in Debt Financing — On September 13, 2023, we completed the offering of $400 million in aggregate principal amount of our 7.15% Senior Notes due 2033 (the “2033 Notes”). The net proceeds before offering expenses were approximately $396 million, which we used to repay amounts outstanding under our revolving credit facility.

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On August 29, 2023, we entered into Amendment No. 4 to Amended and Restated Credit Agreement (the “Credit Agreement Amendment”), which amended our Amended and Restated Credit Agreement, dated as of March 27, 2018 (as amended, the “Credit Agreement”), by and among us, as borrower, Wells Fargo Bank, National Association, as administrative agent, letter of credit issuer, swing line lender and lender and each of the other letter of credit issuers and lenders party thereto.

The Credit Agreement Amendment, among other things, (i) deemed certain outstanding letters of credit issued for the account of BEP Diamond Holdings Corp. (the entity we acquired in the Ulterra acquisition) with a face amount of $2.5 million to have been issued under the Credit Agreement, and (ii) extended the maturity date for $85 million of revolving credit commitments of certain lenders under the Credit Agreement from March 27, 2025 to March 27, 2026. As a result, of the $600 million of revolving credit commitments under the Credit Agreement, the maturity date for $501.7 million of such commitments is March 27, 2026; the maturity date for $48.3 million of such commitments is March 27, 2025; and the maturity date for the remaining $50 million of such commitments is March 27, 2024.

As of December 31, 2023, we had no borrowings outstanding under our revolving credit facility. We had $2.6 million in letters of credit outstanding under the Credit Agreement at December 31, 2023 and, as a result, had available borrowing capacity of approximately $597 million at that date.

During the first quarter of 2023, we elected to repurchase portions of our 3.95% Senior Notes due 2028 (the “2028 Notes”) and our 5.15% Senior Notes due 2029 (the “2029 Notes”) in the open market. The principal amounts retired through these transactions totaled $6.0 million of our 2028 Notes and $3.0 million of our 2029 Notes, plus accrued interest. We recorded corresponding gains on the extinguishment of these amounts totaling $0.8 million and $0.3 million, respectively, net of the proportional write-off of associated deferred financing costs and original issuance discounts. These gains are included in “Interest expense, net of amount capitalized” in our consolidated statements of operations included as a part of Item 8 of this Report.

During the fourth quarter of 2022, we elected to repurchase portions of our 2028 Notes and 2029 Notes (as defined above) in the open market. The principal amounts retired through these transactions totaled $21.0 million of our 2028 Notes and $1.4 million of our 2029 Notes, plus accrued interest. We recorded corresponding gains on the extinguishment of these amounts totaling $2.3 million and $0.1 million, respectively, net of the proportional write-off of associated deferred financing costs and original issuance discounts. These gains are included in “Interest expense, net of amount capitalized” in our consolidated statements of operations included as a part of Item 8 of this Report.

Impact on our Business from Oil and Natural Gas Prices and Other Factors — Our revenues, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas, expectations about future prices, and upon our customers’ ability to access, and willingness to deploy, capital to fund their operating and capital expenditures. During periods of improved oil and natural gas prices, the capital spending budgets of oil and natural gas operators tend to expand, which generally results in increased demand for our services. Conversely, in periods when oil and natural gas prices are relatively low or when our customers have a reduced ability to access, or willingness to deploy capital, the demand for our services generally weakens, and we experience downward pressure on pricing for our services. Even during periods of historically moderate or high prices for oil and natural gas, companies exploring for oil and natural gas may cancel or curtail programs or reduce their levels of capital expenditures for exploration and production for a variety of reasons, which could reduce demand for our services. We may also be impacted by delayed customer payments and payment defaults associated with customer liquidity issues and bankruptcies.

The North American oil and natural gas services industry is cyclical and at times experiences downturns in demand. During these periods, there has been substantially more oil and natural gas service equipment available than necessary to meet demand. As a result, oil and natural gas service contractors have had difficulty sustaining profit margins and, at times, have incurred losses during the downturn periods. We cannot predict either the future level of demand for our oil and natural gas services or future conditions in the oil and natural gas service businesses.

In addition to the dependence on oil and natural gas prices and demand for our services, we are highly impacted by operational risks, competition, labor issues, weather, the availability, from time to time, of products used in our businesses, supplier delays and various other factors that could materially adversely affect our business, financial condition, cash flows and results of operations. See “Risk Factors” in Item 1A of this Report.

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For the three years ended December 31, 2023, our operating revenues and net income consisted of the following (dollars in thousands):

Results of Operations

Effective as of the third quarter of 2023, we revised our reportable segments to align with certain changes in how our Chief Operating Decision Maker (“CODM”) manages and allocates resources to our business as a result of the Ulterra acquisition and NexTier merger. We now have the following reportable business segments: (i) drilling services, (ii) completion services and (iii) drilling products. Accordingly, we recast our results of operations for the first half of 2023 and the year ended December 31, 2022 to align with our revised reportable segments.

Comparison of the years ended December 31, 2023 and 2022

The following tables summarize results of operations by business segment for the years ended December 31, 2023 and 2022:

(1)
Drilling services segment represents our contract drilling, directional drilling, oilfield technology and electrical controls and automation businesses.

(2)
Adjusted gross profit is defined as revenues less direct operating costs (excluding depreciation, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross profit to adjusted gross profit by segment.

(3)
Operational data relates to our contract drilling business. A rig is considered to be operating if it is earning revenue pursuant to a contract on a given day.

Revenues increased primarily due to improved pricing from our contract drilling business within the United States.

Direct operating costs increased primarily due to inflationary pressure on labor and supplies.

The increase in capital expenditures was primarily due to higher maintenance capital expenditures related to upgrading of certain rig components.

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(1)
Completion services represents the combination of well completion business from the NexTier merger and our legacy pressure pumping business.

(2)
Adjusted gross profit is defined as revenues less direct operating costs (excluding depreciation, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross profit to adjusted gross profit by segment.

The changes for the year ended December 31, 2023 as compared to December 31, 2022 can be primarily attributed to the NexTier merger, which closed on September 1, 2023. The NexTier merger had a material impact on our reported results of operations. In order to provide a more meaningful basis for comparison, the discussion on changes below is focused on changes between comparable periods, excluding the effects of the NexTier merger. However, these comparisons do not necessarily reflect what the results of our legacy pressure pumping business would have been had the NexTier merger not occurred and our legacy pressure pumping business continued to operate as a standalone business.

Completion services revenues and direct operating costs, excluding the effects of the NexTier merger, decreased $80.5 million and $49.3 million, or 7.9% and 6.3%, respectively due to calendar inefficiencies and lower customer pricing in 2023.

Selling, general and administrative expense, excluding the effects of the NexTier merger, was relatively flat, totaling $9.5 million in 2023 compared to $8.8 million in 2022.

Depreciation, amortization and impairment, excluding the effects of the NexTier merger, increased $44.2 million, or 45%. The increase was primarily attributable to the change in the estimated useful lives of certain components to reflect recent trends in increased intensity and pumping hours per day in servicing larger jobs. See Note 1 of Notes to consolidated financial statements for additional information on this change in accounting estimate.

Capital expenditures, excluding the effects of the NexTier merger, decreased $32.8 million or 23.8%. The decrease was primarily due to the activation of our twelfth spread in 2022.

(1)
Adjusted gross profit is defined as revenues less direct operating costs (excluding depreciation, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross profit to adjusted gross profit by segment.

The results of our drilling products segment reflect the operations of our Ulterra acquisition, from the closing date of August 14, 2023 until December 31, 2023. As such, there were no comparable results for the year ended December 31, 2022.

Direct operating costs and depreciation, amortization and impairment were approximately $11.0 million and $18.0 million higher than they would have otherwise been, respectively, as a result of the step up to fair value of our drill bits in accordance with purchase accounting for a business combination.

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(1)
Adjusted gross profit is defined as revenues less direct operating costs (excluding depreciation, depletion, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross profit to adjusted gross profit by segment.

Revenue decreased from 2022 primarily due to a $10.5 million decrease in our oil and natural gas revenues resulting from unfavorable crude oil market prices and decreased production. Average WTI-Cushing prices in 2023 were $77.58 per barrel as compared to $94.90 per barrel in 2022. This decrease was partially offset by a $4.7 million increase in revenues from our oilfield rentals business.

Selling, general and administrative expense increased primarily due to increased personnel costs as a result of higher headcount, wage growth and changes in stock-based compensation. A portion of the increased personnel costs resulted from incremental headcount for corporate functions as part of the NexTier merger.

Merger and integration expense increased due to closing the Ulterra acquisition and NexTier merger in 2023. The increase was primarily attributable to $84.8 million of accelerated stock-based compensation expense and additional cash compensation associated with severance payments as well as certain legal, financial advisory, and other professional fees in order to consummate the transactions.

Other operating income, net increased primarily due to a $5.2 million favorable legal settlement and a $6.5 million reversal of cumulative compensation costs associated with certain performance-based restricted stock units in 2023.

Interest income increased due to interest received from a higher average cash balance in 2023.

Interest expense increased due to the issuance of 2033 Notes in the third quarter of 2023 and finance leases acquired as part of the Ulterra acquisition and NexTier merger.

The increase in capital expenditures was primarily due to the purchase of an aircraft in 2023.

Comparison of the years ended December 31, 2022 and 2021

Effective as of the third quarter of 2023, we revised our reportable segments to align with certain changes in how our CODM manages and allocates resources to our business as a result of the Ulterra acquisition and NexTier merger. We now have the following reportable business segments: (i) drilling services, (ii) completion services, and (iii) drilling products. Accordingly, we recast our results of operations for the years ended December 31, 2022 and 2021 to align with our revised reportable segments.

The following tables summarize our recast results of operations by business segment for the years ended December 31, 2022 and 2021:

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(1)
Drilling services segment represents our contract drilling, directional drilling, oilfield technology and electrical controls and automation businesses.

(2)
Adjusted gross profit is defined as revenues less direct operating costs (excluding depreciation, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross profit to adjusted gross profit by segment.

(3)
Operational data relates to our contract drilling business. A rig is considered to be operating if it is earning revenue pursuant to a contract on a given day.

Revenues increased primarily due to an increase in operating days and improved pricing within our contact drilling business as well as increased job activity and improved pricing within our directional drilling business. Average revenue per operating day increased primarily due to improved pricing.

Direct operating costs increased due to an increase in operating days, increased reactivation costs and inflationary cost pressure on labor and supplies within our contract drilling business. A portion of the increase in direct operating costs related to increased job activity and cost inflation within our directional drilling business.

Depreciation, amortization and impairment expense decreased primarily due to a $220 million impairment charge related to the abandonment of 43 legacy non-super-spec rigs and contract drilling equipment and the abandonment of an $11.4 million developed technology intangible asset and $2.5 million of directional drilling equipment in 2021. Additionally, depreciation, amortization and impairment expense decreased partially due to a lower depreciable asset base during 2022 as a result of the impairment charge taken in 2021.

The increase in capital expenditures was primarily due to rig reactivations, higher maintenance capital expenditures and upgrading certain rig components.

(1)
Completion services in 2022 and 2021 represents only our legacy pressure pumping business as the NexTier merger was completed in 2023.

(2)
Adjusted gross profit is defined as revenues less direct operating costs (excluding depreciation, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross profit to adjusted gross profit by segment.

Revenues increased primarily due to an increase in the number of higher revenue fracturing jobs, improved pricing and continued improvement in asset utilization and efficiency.

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Direct operating costs increased primarily due to an increase in the number of higher cost fracturing jobs as well as inflationary cost pressure on labor and supplies.

Depreciation, amortization and impairment expense decreased due to a lower depreciable asset base in 2022 partially as a result of a $32.2 million impairment charge taken in 2021. This impairment charge was related to the abandonment of approximately 0.2 million horsepower within our fleet. Additionally, a portion of the decrease related to certain equipment that reached the end of its useful life during 2022. This decrease in 2022 outpaced incremental depreciation resulting from equipment additions in 2020 and 2021, when our capital expenditures were significantly lower.

The increase in capital expenditures was primarily due to costs associated with reactivating stacked equipment as well as upgrades and the increase in maintenance capital expenditures associated with a higher average number of active spreads.

Our drilling products segment was added through our acquisition of Ulterra in 2023. As such, there were no results for the years ended December 31, 2022 and 2021.

(1)
Adjusted gross profit is defined as revenues less direct operating costs (excluding depreciation, depletion, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross profit to adjusted gross profit by segment.

Revenue increased from 2021 primarily due to a $17.7 million increase in our oilfield rentals business revenues due to higher service volumes and improved pricing as well as a $13.5 million increase in our oil and natural gas revenues resulting from favorable crude oil market prices and increased production. Average WTI-Cushing prices in 2022 were $94.90 per barrel as compared to $68.14 per barrel in 2021.

Direct operating costs increased due to incremental production costs from our oil and natural gas assets as well as a higher service volume provided by our oilfield rentals business and cost inflation.

Depreciation, depletion, amortization and impairment increased primarily due to a $4.5 million impairment in our oil and natural gas assets in 2022.

The increase in capital expenditures was primarily related to incremental spending in our oilfield rentals and oil and natural gas businesses.

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Selling, general and administrative expense increased primarily due to increased personnel costs as a result of higher headcount, wage growth and changes in stock-based compensation.

Merger and integration expenses were recognized in 2021 related to the Pioneer acquisition, which closed on October 1, 2021, and the subsequent divestiture of Pioneer’s well servicing rig business and wireline business, which closed on December 31, 2021.

Other operating (income) expenses, net includes net gains associated with the disposal of assets. Accordingly, the related gains or losses have been excluded from the results of specific segments. The $12.5 million other operating income in 2022 was primarily due to the release of an $11.5 million cumulative translation adjustment from accumulated other comprehensive income into net income (loss) in our consolidated statements of operations upon substantially completing our exit from our Canadian operations.

Interest expense was favorably impacted by a gain on debt extinguishment of $2.5 million associated with the repurchase of portions of our 2028 Notes and 2029 Notes in 2022. Excluding the effects of the gain, interest expense would have increased by $0.7 million, a 1.8% increase. Additionally, on December 30, 2021, we repaid the final $50 million of borrowings under the 2019 Term Loan Agreement, and as a result had no remaining borrowings under the Term Loan Agreement as of December 31, 2021. Accordingly, we did not incur interest expense related to the Term Loan Agreement in 2022.

The $3.0 million change in other expense was primarily due to foreign currency adjustments related to our Colombian operations.

Income Taxes

The effective tax rate increased by approximately 12.0% to 19.9% for 2023 compared to 7.9% for 2022. Our effective income tax rate fluctuates based on, among other factors, changes in pre-tax income in countries with varying statutory tax rates, changes in valuation allowances, and the impacts of various other permanent adjustments.

The ability to recognize a portion of our U.S. federal and state net operating losses resulted in a significant impact, through changes in valuation allowances, in our effective tax rate for the year ended December 31, 2023. This benefit was partly offset by state and local income taxes and various other permanent adjustments.

We continue to monitor income tax developments in the United States and other countries where we have legal entities. We will incorporate into our future financial statements the impacts, if any, of future regulations and additional authoritative guidance when finalized.

Liquidity and Capital Resources

Our primary sources of liquidity are cash and cash equivalents, availability under our revolving credit facility and cash provided by operating activities. As of December 31, 2023, we had approximately $435 million in working capital, including $193 million of cash and cash equivalents, and approximately $597 million available under our revolving credit facility.

As part of the NexTier merger, we assumed the obligations of NexTier Completions Solutions Inc. (“NCS”) under a Master Loan and Security Agreement (as amended, the “Master Agreement”) with Caterpillar Financial Services Corporation. The Master Agreement allows NCS to enter into secured equipment financing term loans from time to time (the “Equipment Loans”). The Equipment Loans may be drawn in multiple tranches, with each loan evidenced by a separate promissory note. The Master Agreement and the Equipment Loans contain customary affirmative and negative covenants, including limitations on further encumbrance of the collateral other than the applicable loans under the Master Agreement. We were in compliance with these covenants at December 31, 2023. The Equipment

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Loans bear interest at a rate of 5.25% per annum, and we pay interest on the 1st of each month. The Equipment Loans will mature on June 1, 2025.

On August 29, 2023, we entered into the Credit Agreement Amendment, which amended our Credit Agreement. The Credit Agreement Amendment, among other things, (i) deemed certain outstanding letters of credit issued for the account of BEP Diamond Holdings Corp. (the entity we acquired in the Ulterra acquisition) with a face amount of $2.5 million to have been issued under the Credit Agreement and (ii) extended the maturity date for $85 million of revolving credit commitments of certain lenders under the Credit Agreement from March 27, 2025 to March 27, 2026. As a result, of the $600 million of revolving credit commitments under the Credit Agreement, the maturity date for $501.7 million of such commitments is March 27, 2026; the maturity date for $48.3 million of such commitments is March 27, 2025; and the maturity date for the remaining $50 million of such commitments is March 27, 2024.

The Credit Agreement is a committed senior unsecured revolving credit facility that permits aggregate borrowings of up to $600 million, including a letter of credit facility that, at any time outstanding, is limited to $100 million and a swing line facility that, at any time outstanding, is limited to the lesser of $50 million and the amount of the swing line provider’s unused commitment. Subject to customary conditions, we may request that the lenders’ aggregate commitments be increased by up to $300 million, not to exceed total commitments of $900 million.

Loans under the Credit Agreement bear interest by reference, at our election, to the SOFR rate (subject to a 0.10% per annum adjustment) or base rate, in each case subject to a 0% floor. The applicable margin on SOFR rate loans varies from 1.00% to 2.00% and the applicable margin on base rate loans varies from 0.00% to 1.00%, in each case determined based on our credit rating. As of December 31, 2023, the applicable margin on SOFR rate loans was 1.75% and the applicable margin on base rate loans was 0.75%. A letter of credit fee is payable by us equal to the applicable margin for SOFR rate loans times the daily amount available to be drawn under outstanding letters of credit. The commitment fee rate payable to the lenders varies from 0.10% to 0.30% based on our credit rating.

None of our subsidiaries are currently required to be a guarantor under the Credit Agreement. However, if any subsidiary guarantees or incurs debt, which does not qualify for certain limited exceptions and is otherwise, in the aggregate with all other similar debt, in excess of Priority Debt (as defined in the Credit Agreement), such subsidiary is required to become a guarantor under the Credit Agreement.

The Credit Agreement contains representations, warranties, affirmative and negative covenants and events of default and associated remedies that we believe are customary for agreements of this nature, including certain restrictions on our ability and the ability of each of our subsidiaries to grant liens and on the ability of each of our non-guarantor subsidiaries to incur debt. If our credit rating is below investment grade at both Moody’s and S&P, we will become subject to a restricted payment covenant, which would generally require us to have a Pro Forma Debt Service Coverage Ratio (as defined in the Credit Agreement) greater than or equal to 1.50 to 1.00 immediately before and immediately after making any restricted payment. Restricted payments include, among other things, dividend payments, repurchases of our common stock, distributions to holders of our common stock or any other payment or other distribution to third parties on account of our or our subsidiaries’ equity interests. Our credit rating is currently investment grade at both credit rating agencies. The Credit Agreement also requires that our total debt to capitalization ratio, expressed as a percentage, not exceed 50% as of the last day of each fiscal quarter. The Credit Agreement generally defines the total debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the end of the most recently ended fiscal quarter. We were in compliance with these covenants at December 31, 2023.

On March 16, 2015, we entered into a Reimbursement Agreement (the “Reimbursement Agreement”) with The Bank of Nova Scotia (“Scotiabank”), pursuant to which we may from time to time request that Scotiabank issue an unspecified amount of letters of credit. As of December 31, 2023, we had $87.7 million in letters of credit outstanding under the Reimbursement Agreement.

Under the terms of the Reimbursement Agreement, we will reimburse Scotiabank on demand for any amounts that Scotiabank has disbursed under any of our letters of credit issued thereunder. Fees, charges and other reasonable expenses for the issuance of letters of credit are payable by us at the time of issuance at such rates and amounts as are in accordance with Scotiabank’s prevailing practice. We are obligated to pay to Scotiabank interest on all amounts not paid by us on the date of demand or when otherwise due at the LIBOR rate plus 2.25% per annum, calculated daily and payable monthly, in arrears, on the basis of a calendar year for the actual number of days elapsed, with interest on overdue interest at the same rate as on the reimbursement amounts. A letter of credit fee is payable by us equal to 1.50% times the amount of outstanding letters of credit.

We have also agreed that if obligations under the Credit Agreement are secured by liens on any of our or our subsidiaries’ property, then our reimbursement obligations and (to the extent similar obligations would be secured under the Credit Agreement) other obligations under the Reimbursement Agreement and any letters of credit will be equally and ratably secured by all property subject to such liens securing the Credit Agreement.

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Pursuant to a Continuing Guaranty dated as of March 16, 2015, our payment obligations under the Reimbursement Agreement are jointly and severally guaranteed as to payment and not as to collection by our subsidiaries that from time to time guarantee payment under the Credit Agreement. None of our subsidiaries are currently required to guarantee payment under the Credit Agreement.

We had $92.4 million of outstanding letters of credit at December 31, 2023, which was comprised of $87.7 million outstanding under the Reimbursement Agreement, $2.5 million outstanding under the Credit Agreement, and $2.2 million outstanding with financial institutions providing for short-term borrowing capacity, overdraft protection and bonding requirements. We maintain these letters of credit primarily for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under terms of the underlying insurance contracts and compliance with contractual obligations. These letters of credit expire annually at various times during the year and are typically renewed.

Our outstanding long-term debt at December 31, 2023 was $1.2 billion and consisted of $483 million of our 2028 Notes, $345 million of our 2029 Notes, $400 million of our 2033 Notes and $18.7 million of our Equipment Loans. We were in compliance with all covenants under the associated agreements and indentures at December 31, 2023.

For a full description of the Credit Agreement, the Reimbursement Agreement, the 2028 Notes, the 2029 Notes, the 2033 Notes and the Equipment Loans, see Note 9 of Notes to consolidated financial statements included as a part of Item 8 of this Report.

On August 29, 2023, we entered into a Term Loan Agreement with Wells Fargo Bank, National Association, as administrative agent and a lender, and the other lenders party thereto (the “Term Loan Agreement”). The Term Loan Agreement was a committed senior unsecured term loan facility (the “Term Loan Facility”) that permitted a single borrowing of up to $300 million, which could be drawn by us on or before November 27, 2023. We terminated the Term Loan Facility on September 13, 2023 and, as a result, the commitments under the Term Loan Agreement also terminated in full. We did not borrow under the Term Loan Facility.

Cash Requirements

We believe our current liquidity, together with cash expected to be generated from operations, should provide us with sufficient ability to fund our current plans to maintain and make improvements to our existing equipment, service our debt, pay cash dividends and repurchase our common stock and senior notes for at least the next 12 months.

If we pursue other opportunities that require capital, we believe we would be able to satisfy these needs through a combination of working capital, cash flows from operating activities, borrowing capacity under our revolving credit facility or additional debt or equity financing. However, there can be no assurance that such capital will be available on reasonable terms, if at all.

A portion of our capital expenditures can be adjusted and managed by us to match market demand and activity levels. Based on our current outlook for activity, we expect our capital expenditures for 2024 to be approximately $740 million. The majority of these expenditures are expected to be used for normal, recurring items necessary to support our business.

We anticipate $96.4 million of expenditures in 2024 related to various contractual obligations such as certain commitments to purchase proppants and lease liabilities.

As of December 31, 2023, we had working capital of $435 million, including cash and cash equivalents of $193 million, compared to working capital of $278 million, including cash and cash equivalents of $138 million, at December 31, 2022.

During 2023, our sources of cash flow included:

•
$1.0 billion from operating activities,

•
$26 million in proceeds from the disposal of property and equipment; and

•
$396 million in net proceeds before offering expenses from the issuance of our 2033 Notes.

During 2023, our uses of cash flow and borrowings under our revolving credit facility included:

•
$616 million to make capital expenditures for the betterment and refurbishment of drilling services and completion services equipment and, to a much lesser extent, equipment for our other businesses, to acquire and procure equipment to support our drilling services, completion services, drilling products, oilfield rentals and manufacturing operations, to acquire an aircraft and to fund investments in oil and natural gas properties on a non-operating working interest basis,

•
$357 million, net of acquired cash, for the Ulterra acquisition,

•
$65 million, net of acquired cash, for the NexTier merger,

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•
$201 million for repurchases of our common stock,

•
$100 million to pay dividends on our common stock,

•
$16 million for payments related to finance leases,

•
$8 million for repurchases of our 2028 Notes and 2029 Notes, and

•
$12 million for other investing and financing activities

We paid cash dividends during the year ended December 31, 2023 as follows:

On February 14, 2024, our Board of Directors approved a cash dividend on our common stock in the amount of $0.08 per share to be paid on March 15, 2024 to holders of record as of March 1, 2024. The amount and timing of all future dividend payments, if any, are subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of our debt agreements and other factors. Our Board of Directors may, without advance notice, reduce or suspend our dividend in order to improve our financial flexibility and position our company for long-term success. There can be no assurance that we will pay a dividend in the future.

We may, at any time and from time to time, seek to retire or purchase our outstanding debt for cash through open-market purchases, privately negotiated transactions, redemptions or otherwise. Such repurchases, if any, will be upon such terms and at such prices as we may determine, and will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

In September 2013, our Board of Directors approved a stock buyback program. In April 2023, our Board of Directors approved an increase of the authorization under the stock buyback program to allow for an aggregate of $300 million of future share repurchases. All purchases executed to date have been through open market transactions. Purchases under the buyback program are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Purchases may be made at any time without prior notice. There is no expiration date associated with the buyback program. As of December 31, 2023, we had remaining authorization to purchase approximately $206 million of our outstanding common stock under the stock buyback program. In February 2024, our Board of Directors approved an increase of the authorization under the stock buyback program to allow for an aggregate of $1 billion of future share repurchases. Shares of stock purchased under the buyback program are held as treasury shares.

We acquired shares of stock from employees during 2023, 2022 and 2021 that are accounted for as treasury stock. Certain of these shares were acquired to satisfy the exercise price and employees’ tax withholding obligations upon the exercise of stock options. The remainder of these shares were acquired to satisfy payroll withholding obligations upon the settlement of performance unit awards and the vesting of restricted stock units. These shares were acquired at fair market value. These acquisitions were made pursuant to the terms of the Patterson-UTI Energy, Inc. Amended and Restated 2014 Long-Term Incentive Plan, as amended (the “2014 Plan”) and the Patterson-UTI Energy, Inc. 2021 Long-Term Incentive Plan (the “2021 Plan”), the NexTier Oilfield Solutions Inc. Equity and Incentive Award Plan and the NexTier Oilfield Solutions Inc. (Former C&J Energy) Management Incentive Plan, and not pursuant to the stock buyback program. Upon the issuance of shares for the Pioneer acquisition in October 2021, we withheld shares with respect to Pioneer employees’ tax withholding obligations.

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Treasury stock acquisitions during the years ended December 31, 2023, 2022 and 2021 were as follows (dollars in thousands):